Compact Overhead Line Design: AC and DC Lines (CIGRE Green Books) 3031445236, 9783031445231

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CIGRE Green Books Compact Studies

CIGRE Study Committee B2: Overhead Lines

Rob Stephen  Javier Iglesias Editors

Compact Overhead Line Design AC and DC Lines

CIGRE Green Books

Compact Studies Series Editor CIGRE, International Council on Large Electric Systems, Paris, France

CIGRE presents their expertise in compact professional books on electrical power networks. These books are of a self-contained concise character, covering the entire knowledge of the subject within power engineering. The books are created by CIGRE experts within their study committees and are recognized by the engineering community as the top reference books in their fields.

Rob Stephen · Javier Iglesias Editors

Compact Overhead Line Design AC and DC Lines

Editors Rob Stephen CIGRE Durban, South Africa

Javier Iglesias Red Eléctrica de España Madrid, Spain

ISSN 2367-2625 ISSN 2367-2633 (electronic) CIGRE Green Books ISSN 2509-2812 ISSN 2509-2820 (electronic) Compact Studies ISBN 978-3-031-44523-1 ISBN 978-3-031-44524-8 (eBook) https://doi.org/10.1007/978-3-031-44524-8 © Springer Nature Switzerland AG 2024 This work is subject to copyright. All rights are reserved by the Publisher, whether the whole or part of the material is concerned, specifically the rights of reprinting, reuse of illustrations, recitation, broadcasting, reproduction on microfilms or in any other physical way, and transmission or information storage and retrieval, electronic adaptation, computer software, or by similar or dissimilar methodology now known or hereafter developed. The use of general descriptive names, registered names, trademarks, service marks, etc. in this publication does not imply, even in the absence of a specific statement, that such names are exempt from the relevant protective laws and regulations and therefore free for general use. The publisher, the authors, and the editors are safe to assume that the advice and information in this book are believed to be true and accurate at the date of publication. Neither the publisher nor the authors or the editors give a warranty, expressed or implied, with respect to the material contained herein or for any errors or omissions that may have been made. The publisher remains neutral with regard to jurisdictional claims in published maps and institutional affiliations. This Springer imprint is published by the registered company Springer Nature Switzerland AG The registered company address is: Gewerbestrasse 11, 6330 Cham, Switzerland Paper in this product is recyclable.

This book is dedicated to Dale A. Douglass, Engineer, Colleague, Mentor, Musician, Friend.

Foreword

The need to build new overhead lines enabling transfer of power from renewable and other generating sources is increasing. The increased difficulty in obtaining Right of Way permissions requires innovative solutions with respect to placing the lines in available Right of Way allocations. In many cases, the Right of Way available may be far narrower than previously used. Environmental concerns also require low-profile, less obtrusive designs especially in urban areas. To meet these requirements, it is necessary to design lines with clearances far less than the conventional designs. This increases the stress on the conductors as well as affects the performance of the line. This book describes the parameters that need to be considered with regard to compaction as well as performance, maintenance, and construction. Similarly, compaction will increase the surge impedance loading of and AC line. This will enable a higher power transfer over a specific corridor. The level of compaction as well as examples is given. Although many may not realize it, voltage upgrading of a line is also a form of compaction. The need for voltage upgrading is due to the increased need for power transfer in existing corridors. The same considerations apply to voltage-upgraded lines as for compact lines. The case studies provided for AC, DC, and voltage upgrades enable the reader to understand how the concept of compaction has been applied in different parts of the world. This book provides a useful guide to the engineer faced with the constraints of power transfer either from limited Right of Way permissions or the need for lower impedance on existing or new lines. Montreal, Canada

Pierre Van Dyke Study Committee B2 Chair

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Preface

Compact lines refer to overhead power lines whose clearances are less than conventional lines. The reasons for using compact lines can be attributed to building lines in a narrow Right of Way, aesthetic reasons, and to providing a higher surge impedance loading (for AC lines). Lines that are upgraded in voltage without increasing the phase or pole spacing are also considered compact. When the distances between the phases or poles are reduced to earth or other phases and poles, the stress on the conductors increases. This can result in a poorer performance of the line or increased corona and audible noise issues. This book deals with the parameters that designers need to consider when dealing with compacting of lines. This includes the electrical aspects such as calculation of the inductance, capacitance, and surge impedance for AC lines as well as the corona, audible noise, radio interference, losses, and ground-level electric field effects. As the corona issues are extremely difficult to rectify once the line is built, it is desirable to ensure that there is a buffer between the corona inception voltage and the actual surface gradient. The reduction of the clearances also affects the insulation coordination of the line (both AC and DC). The book covers overvoltages, insulation strength, the calculation procedure for different temporary overvoltages, and the insulation coordination for the neutral conductor (DC). An example is given for calculation of air clearances for AC lines. Conductor swing is also described with an application example. Insulator pollution characteristics are described for AC and DC conditions enabling design of insulator strings for compact lines. The next chapter describes possible phase configuration, conductor selection, and hardware designs. The conductor selection is based on economic considerations as well as surface gradient considerations. Tower design options are also described with different considerations provided for tower compaction. As the distance between phases or poles is reduced, the issue of galloping needs to be considered. Various mitigation methods are described including interphase spacers which prevent the phases from moving too close to one another under galloping conditions.

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Preface

Maintenance of compact lines is also critical. In many cases, the reason for using compact lines is that the right of way is severely constrained. This implies that more than one line cannot normally be built in the same or nearby servitudes. The use of live line maintenance techniques is required. The minimum approach distances for both AC and DC are described as well as live line working methods, procedures, and case studies where live line techniques are used on DC lines. A detailed example of the influence of compaction on the electrical design is provided for both AC and DC lines. This includes insulation coordination, geometries to be considered, AC line constants, corona effects for both AC and DC lines. The standards for designs used in different countries are also provided. This includes the overvoltage values, the insulation coordination values, corona effects, and electric and magnetic field limitations. This provides the reader with an indepth knowledge of the different standards and limits that are being applied. The book concludes with several case studies for both AC and DC line compaction projects. A total of 18 case studies are described covering most continents. Similarly, case studies on voltage upgrading on both AC and DC lines are covered. This book is a guideline covering the main aspects relating to the design of compact AC and DC lines. The main concept regarding compact lines is that the electrical stresses are higher than with conventional lines. This higher stress manifests itself in the form of audible noise, compromised insulation coordination for switching and lightning impulses and electric field. In the case of DC lines, this includes increased ion current density at ground level. This guide highlights these areas and allows the reader to understand the aspects that need to be considered when mitigating the effects of the higher electrical stress. The calculation examples show the effect of different design solutions. The reader can optimize his solution initially from these examples prior to the detailed calculations that need to be performed on a specific design. The case studies indicate different practical solutions that have been implemented or are under study in different countries. These case studies focus on the main aspects related to compaction and the various proposals to reduce the distances while keeping acceptable limits to different parameters. Other examples can be found around the world. It includes a novel idea of supporting the conductor bundle with steel cables to reduce the sag. This allows for shorter spans hence narrower right of way. The voltage upgrade example indicates the same concept as a compact line with a different application for increased power flow. This example, although 40 years old, provides an example of the steps required for a reliable upgrade solution. Note that the guide is not a design document but a document by which the reader can assess the aspects required for design of compact lines as well as determine the calculations that need to be undertaken in the completion of a detailed

Preface

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compact line design. It does, however, provide references that will enable the designer to fully design a compact line. Durban, South Africa Madrid, Spain

Rob Stephen Javier Iglesias

Acknowledgements

List of Contributors. (Members and Reviewers of the CIGRE Working Groups B2.62 and B2.63) H. Lugschitz (AT) A. Anand (IN) G. Wu (CN) W. Troppauer (AT) K. Halsan (NO) S. Steevens (DE) J. A. Jardini (BR) G. Persson (SE) L. Barthold (US) C. Wang (CA) D. Woodford (CA) D. Liebhaber (US) E. Marshall (ZA) T. Yamanaka (JP) D. Douglass (US) A. Useros (ES) D. Loudon (NO) M. Salimi (CA) S. Ikoma (JP) J. Lundquist (SE) P. Rodríguez (ES) N. Chen (CN) G. Gheorghita (RO) B. Fife (US) L. Nazimek (PL) J. Fernandes (BR) J. Nolasco (BR) Y. Hachizawa (JP) O. Regis (BR) K. Reich (AT) H. Valente (PT) W. Kiewitt (DE) xiii

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W. Lee (KR) G. Watt (CA) C. Winter (DE) M. Souza (BR) C. Nascimento (BR) K. Papailliou K. Halsan

Acknowledgements

Message from the Secretary General

Dear Readers, From 1969 to 2023, CIGRE has published more than 900 Technical Brochures. A Technical Brochure is a document produced and edited by a CIGRE Working Group, following its specific Terms of Reference. It is published by CIGRE Central Office and available from the CIGRE online library, e-cigre, one of the most comprehensive, accessible databases of relevant technical literature on power engineering. Between 30 and 45, new Technical Brochures are published yearly, and these Brochures are announced in Electra, CIGRE’s bimonthly journal. They are accessible from e-cigre free of charge for CIGRE members or at a certain price for non-members. In 2011, Dr. Konstantin Papailiou proposed the Technical Council, the Green Book concept to valorize the collective work of CIGRE Study Committees accumulated over many decades, by putting together all the Technical Brochures of a given field in a single book. In 2014, CIGRE published its first Green Book, the one on Overhead Lines, paving the way to a new CIGRE publication collection. In 2015, CIGRE decided to cooperate with Springer for the edition and publication of its next Green Books, as “Major Reference Works,” and to distribute them through the vast network of this well-known international publisher. In 2016, the collection enriched itself with a new category of Green Books, the CIGRE “Compact Series,” to satisfy the needs of the Study Committees when they want to publish shorter, concise volumes. The first CIGRE Compact Book, prepared by Study Committee D2 under the title “Utility Communication Networks and Services,” became the best seller of the collection. The concept of the CIGRE Green Books series has continued to evolve, with the introduction of a third subcategory of the series, the “CIGRE Green Book Technical Brochures” (GBTB). Like for the other publications of CIGRE, e-cigre provides the references of all the books of the Green Books series, which anyone can order from the SPRINGER’s platform. A special discount applies for CIGRE members. xv

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Message from the Secretary General

Each of the co-authors/editors of a Green Book will receive a free copy in recognition of their contribution to this collective work. This book prepared by Dr. Rob Stephen (Editor) and Javier Iglesias (Co-editor) fits into CIGRE plans to co-publish new Green Books by the different Study Committees, with a goal to expand the series at a pace of one or two volumes per year. In this case, the editors mentioned were the working group chairpersons for compact AC and DC lines, respectively. This book is a combination of the two Brochures. In a few final words, I would like to thank and congratulate all the authors, contributors, and reviewers of this specific publication on the Compact Overhead Line Design: AC and DC. Paris, France August 2023

Philippe Adam Secretary General

Study Committee B2

CIGRE Study Committee B2 Overhead lines covers the design, construction, operation, and maintenance of overhead lines. This includes the mechanical and electrical design and experimental validation of new line components (e.g., conductors, ground wires, insulators, accessories, structures, and their foundations), the study of line performance in service, assessment of aged line components, line maintenance including robotics, refurbishment and life extension as well as upgrading and uprating of existing overhead lines. In a world where there is a clear desire to improve access to electricity and to electrify processes that currently use other energy sources, overhead lines play a key role for the electricity system of the future. The activities of SC B2 are fully in line with this important aspect of CIGRE’s mission. The technical guidelines of SC B2 are: • • • •

Increase the ampacity of existing lines Ensure or improve line reliability. Ensure environmentally compatible lines. Develop working methods and new tools.

The main areas of interest of B2 are: • • • • • • • • • • •

Route selection. Optimized line design. Line maintenance and service. Refurbishment of existing lines. Design specifications. Increase in the power of existing lines. Asset management guidelines. Real-time monitoring systems. New materials. Sustainability of line components. Minimizing the environmental impact of lines.

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Study Committee B2

At present, B2 has 27 active working groups including three Joint Working Groups with other SCs and 552 experts contribute in WGs, from 45 countries. B2 has published 96 Technical Brochures since 1994. The CIGRE Green Books are the leading reference publication in the field of electrical network. They provide knowledge from experts in the field. So far, B2 has published four Green Books including the first one in 2017 as well as a joint Green Book. With its theory, calculations, and case studies, this Green Book on compact overhead power line design will be an important and valuable tool for line designers. I would therefore like to express my sincere thanks to the two editors and the authors for all their efforts to make this knowledge accessible to the reader. Pierre Van Dyke CIGRE Study Committee B2 Chair

Executive Summary

This book explains the concept of overhead power line compaction. A compact overhead power line (AC or DC) is an overhead power line for which the distances between the phases or the poles are much less than those used in conventional designs. The purpose of compaction is primarily for reduced Right of Way (ROW) and/or height. These aspects are often critical to gain the necessary permissions or approval for the line. However, reducing the horizontal distances and heights may result in increased electric fields and other effects which may become the limiting factor and are necessary to manage in the design of a compact power line. Therefore, compacting simply means maximizing the power transmitted on a given cross section or, inversely, minimizing that cross section for a given power transfer requirement. For DC overhead power lines, increased power flow can only be realized by increasing the current through the conductors and/or increasing line voltage. In AC, however, it can also be done by bundle expansion and phase compaction due to the variation of the impedance of the line. So, compaction does not have the same effect in AC or DC lines, and the constraints associated with compaction also differ (corona-related effects, clearances, arrangements…). In addition to the theory, the book includes actual calculations of electric and magnetic parameters for a variety of configurations. The parameters used in different countries are also tabulated for reference. Note that each set of values used by a country needs to be adopted as they interrelate. It is not recommended to use one limit from one country and another limit from another in a specific line design unless the designer is aware of the interaction between the parameters. Case studies on line compaction designs are described with relation to phase or pole compaction and re-arrangement. Voltage upgrading is also treated in this book, and some examples are provided. The aim of the book is to provide the design engineer with an understanding of the electrical parameters and methods required in designing compact lines.

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Contents

1 Introduction—Compact Line Definition and Reasons for Use . . . . . . . .

1

2 Electrical Parameters . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .

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3 Insulation Coordination . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .

25

4 Phase/Pole Configuration, Conductor and Hardware . . . . . . . . . . . . . . . .

53

5 Live Line Maintenance Techniques . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 103 6 Construction Techniques . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 131 7 Influence of Compaction on the Electrical Design . . . . . . . . . . . . . . . . . . . . 139 8 Case Studies . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 177 9 Voltage Upgrading . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 271

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About the Editors

Dr. Rob Stephen was born in Johannesburg South Africa. He holds B.Sc., M.Sc., M.B.A. degrees as well as a Ph.D. in overhead line design. He retired from Eskom on January 31, 2020, where he held the position of Master Specialist in the Technology Group responsible for distribution and transmission technologies of all voltages covering both AC and DC. He also held position of Group Capital program manager responsible for electrification and capital projects. He was accountable for demand side management installation of compact fluorescent bulbs (3m) in 2008. He is a past chairman of CIGRE Study Committee B2 on overhead lines and has held positions in CIGRE of Special reporter and working group chairman and has authored over 100 technical papers. He was the international president of CIGRE from 2016–2020, the first African to hold this position. He is a fellow of the South African Institute of Electrical Engineers and was awarded the President’s award in 2016. At time of writing he is a specialist advisor at the University of Kwa Zulu Natal, Durban, where he is developing courses on line design, supervising post-graduate students, and advising and assisting in research matters. e-mail: [email protected]

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About the Editors

Javier Iglesias Project Director at Red Eléctrica de España (Spain). Javier Iglesias was born in Madrid, Spain. He holds B.Sc. and M.Sc. degrees in Mechanical and Electrical Engineering from the “Universidad Pontificia Comillas—ICAI, Spain,” as well as other post-graduate programs on Project Management and Executive Management. He has over twenty-five years’ experience in power transmission systems from different positions and companies. In 2002, Javier joined Red Eléctrica de España, where now is responsible of projects for the transmission system in Spain (400 and 220 kV lines and substations), being in charge of the coordination, engineering, environmental studies, construction works, supplies, permits, authority licenses, and commissioning. He has co-authored over twenty technical publications related to transmission lines, has been convener of two CIGRE Working Groups, and has participated actively in more than fifteen. In CIGRE, he has held positions of National Representative for Study Committee B2, Special Reporter at the Paris Session, and Chair of various conferences and workshops. He received the Technical Council Award in 2018. Now, he is the chairman of the Technical Advisory Group on “Electrical aspects of overhead lines,” president of the Spanish National Committee, and member of the CIGRE Steering Committee. e-mail: [email protected]

1

Introduction—Compact Line Definition and Reasons for Use

Contents 1.1

Definition and Need for Compaction . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 1.1.1 Right of Way (Easement or Servitude) Reduction . . . . . . . . . . . . . . . . . . . . . . . . . . 1.1.2 Visual Impact . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 1.1.3 Power Flow Improvement (AC Lines) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 1.1.4 Voltage Upgrade . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 1.2 Considerations for Compaction . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 1.3 Sustainability . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . References . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .

1 2 4 4 5 6 7 7

Abstract

A compaction of an overhead power line can be considered as a reduction of the line’s cross-section. This reduction implies smaller horizontal and vertical distances of the phases or poles, which has consequences in different aspects. This chapter introduces the general aspects to be taken into consideration for line compaction and the issues that need to be covered for a reliable design.

1.1

Definition and Need for Compaction

For the purposes of this book and based on the definition of compact lines provided by the Electric Power Research Institute (EPRI) [1], a compact overhead power line (AC or DC) is an overhead power line for which the distances between the phases or the poles are much less than those used in conventional designs. This is typically made possible either using special insulators or reducing the overvoltages applied between phases or poles. Note that the concept of “compaction” which implies multiple circuits in a single Right of Way (ROW) is excluded from this definition. © Springer Nature Switzerland AG 2024 R. Stephen and J. Iglesias (eds.), Compact Overhead Line Design, Compact Studies, https://doi.org/10.1007/978-3-031-44524-8_1

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R. Stephen and J. Iglesias

The material for the book is obtained from two CIGRE Technical Brochures [2, 3]. These documents are a result of international collaborative work with experts in the field of compact line design. The work has been peer reviewed and revised with input from the experts providing the latest theory and guidelines available. For DC and AC overhead power lines, compaction may be required due to two main reasons: • Right of Way (easement or servitude) limitations—the obtaining of servitudes for placement of lines is becoming more difficult worldwide. It is often required that large capacity lines are placed in the same servitude width of previous smaller lines, or in corridors that need to be shared with other infrastructures like railroads or highways. Compact lines which permit the line to fit into the smaller servitude width are often the solution. • Visual impact—Compacting the poles usually results in a lower visual impact (lower height and width), which may be more pleasing to the public. This, in turn may result in more acceptance from the public for the line. For AC overhead power lines, compaction may also be required for a third reason: • Increased power flow—The reduction of phase spacing (which can be achieved by reducing the distance between bundle centres or by increasing the bundle diameters), will result in an increase in the Surge Impedance Loading of the line, permitting higher power flow. This is not the case in DC lines, where inductance (L) and capacitance (C) play a secondary role, and the reduction of pole spacing does not implies an increase in the power flow. However, in DC, corona and field phenomena may be quite important and may become a limitation to the ROW or height. More detailed explanations for general DC overhead power line designs can be found in [4].

1.1.1 Right of Way (Easement or Servitude) Reduction The reduction in the servitude width can be achieved in many ways. The servitude width is generally determined by the blow-out of the conductor from the centre line. To reduce the blow-out of the conductor the following can be done: • Use of V instead of I string insulators—the V string will reduce the movement of the insulator under wind conditions. In the case of the I string; the insulator moves increasing the blow out and hence the servitude width requirement. Other arrangements, such as insulated crossarms, Y sets, inverted V configurations, etc., can also be used to limit the conductor blow-out, depending on the case (Fig. 1.1).

1 Introduction—Compact Line Definition and Reasons for Use

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• Use of shorter spans—shorter spans limit the blow-out of the conductor as the conductor is fixed at each tower point. The drawback of this method is that the increase in the number of towers (although the loads and height requirements are lower) increases the cost of the line. Note that the conductor blow-out also depends on the conductor characteristics and mechanical conditions, mainly tension. Bundling configurations or conductor constructions (compact or motion resistant) can reduce the wind force and thus the blow-out. • Use of vertical pole configuration—if the pole configuration is vertical as opposed to flat, the blowout of all phases is the same as would be with the centre phase on a flat configuration. This reduces the tower width and the servitude width required by blow-out. • Reducing the distance between poles/phases—the reduction between poles can be used in any pole configuration be it vertical, flat or asymmetrical. The reduction in the phase spacing will reduce the tower width and servitude width required by blowout in the case of delta or flat configurations and reduce the tower height (improve visual impact). Note that for compact DC lines in narrow corridors, it is likely that the maximum admissible values for the corona-related effects (electric field, ion current, audible noise, etc.) at the edge of the ROW be the governing aspects of the line design. Fig. 1.1 HVDC line using V-string insulators

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R. Stephen and J. Iglesias

1.1.2 Visual Impact The visual impact of an overhead power line is often one of the most critical aspects to obtain the necessary regulatory approval. It is more and more common to study in detail and even simulate from different points of view the visual aspect of the lines before the construction starts to get the permissions. Also, the total height of the overhead power line is often a limitation due to other restrictions like proximity to airports or wildlife considerations, for instance. Therefore, reducing the height of the towers is one of the means to gain acceptability, making the line less visible, avoiding other restrictions. But, as previously mentioned, this has consequences in the design. If the conductors are closer to the ground, some parameters are usually higher (such as the Electric Field or the Ion Current at ground level, or the Audible Noise and the Radio Interference at the edge of the ROW). And the design of the line (and hence the cost) is affected: the number of towers, the span length, and the mechanical load applied. The variables affecting tower height and occupancy are inter-related, so an overall design assessment is required to determine the most efficient solution for each line or portion of a line. Some reasons for reducing the line height are: using flat configurations, shortening spans or using particular conductor designs, like HighTemperature Low Sag (HTLS) conductors. More options and examples can be revised in [5]. But not only the height is crucial to get the public acceptance. The appearance of the towers is a big concern nowadays. Because of that, many tower designs and line concepts are developing around the world, pursuing to make the overhead power lines more visually “acceptable”. Refer to [6], which discusses innovative solutions for aesthetic towers. However, the aesthetics can be subjective, and the visibility can depend on several factors. For example, full body supports are usually more visible from far away (Fig. 1.2).

1.1.3 Power Flow Improvement (AC Lines) Increasing the bundle size can increase the Surge Impedance Loading (SIL) of the line [7]. This is an indication of the increased power flow possible without compensation down the line. The actual power flow will depend on the network that the line is employed in. Table 1.1 indicates the increases that can be achieved by decreasing phase spacing and increasing the bundle diameter as well as the number of sub-conductors in the bundle. Lines employing these approaches are described as High Surge Impedance Loading (HSIL) lines.

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Fig. 1.2 Compact 500 kV AC line with steel pylons

Table 1.1 Increase in surge impedance loading with bundle size increase [7]

Voltage (kV)

SIL traditional TL (MW)

SIL-HSIL (MW)

69

9–12

10–40

138

40–50

50–120

230

120–130

130–440

500

950–1000

1000–2000

1.1.4 Voltage Upgrade Another means to increase power flow is to upgrade the voltage of the line. This places the same stresses electrically on the line as would a compact line at a lower voltage. The same processes and theory apply to both cases. Note that in the case of voltage upgrade the substation equipment will also have to be upgraded which may influence the method used for increasing power transfer. Chapter 9 of this book discusses the voltage upgrading of both AC and DC overhead power lines. It details the main aspects to be considered in the design and provides examples from different countries.

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Considerations for Compaction

When compacting an overhead AC or DC line by reducing the distance between the phases or poles, the following aspects need to be considered. • Air clearances. The flashover reliability may be affected by the pole to pole or phase to phase distance reduction. It depends on the line configuration, and different design options are available to cover this aspect, as can be seen through the document. • Audible noise and radio interference. By decreasing the distance between the poles/phases or increasing the bundle size with the same distance between bundle centres, will increase the surface gradient on the conductors. This may result in increased audible noise as well as radio interference. It is important to check that these levels are within acceptable standards. • Ground level field effects. Electric field and ion current density (DC) at ground level are also dependent on the pole to pole or phase to phase distances. The acceptable limits must not be exceeded. These limits are often considered at the edge of the Right of Way, so compact designs in narrow corridors may be limited by this aspect. • Live line maintenance. The reduction in pole/phase spacing reduces the distances that live workers can operate within. It may be necessary to change the method of working or maintain the line when it is out of service. • Insulation coordination. The ability of the line to withstand lightning and switching surges will be impacted by the reduction in pole spacing. It is important that studies are undertaken to determine if the surges to be experienced on the line will result in flashovers. If so, measures should be taken to ensure reliability of the line is maintained. • Sub-span oscillation. To reduce the surface gradient on the conductors, the bundle size may be reduced. This reduces audible noise and radio interference. However, if the distance between the sub-conductors is less than 15 diameters in the horizontal plane, one may experience sub-span oscillation which can cause damage. This can be mitigated by increasing the number of spacer dampers and checks need to be undertaken to ensure the bundle is mechanically without vibration issues. • Pole to pole or phase to phase clashing. Galloping may cause flashover due to pole/phase conductors moving out of synchronisation (in phase). This may be exacerbated with the reduction in pole to pole or phase to phase distance. In areas where galloping is likely, mitigation measures such as interphase spacers or other anti-galloping devices may be necessary. • Other considerations. It must be noted that in many cases the only possible solution for line routing is sharing corridors with other infrastructures, like for example railways or other transmission lines. The reduction of the distance between the phases/poles may affect these other infrastructures, and the

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interactions must be considered: safety distances, induced effects, maintenance requirements…

1.3

Sustainability

Sustainable Development (SD) is a development that meets the needs of the present without compromising the ability of future generations to meet their own needs [8]. SD is a broad concept, with three pillars that include the Environment, Economy and Society. Our infrastructure systems, including our transmission systems, significantly impact all three pillars. The transmission line industry has the challenge of providing a path for electricity to support societal and economical needs and to facilitate the use of renewable energy sources while balancing negative impacts to the environment and society. Compact transmission design plays a significant role in the future of sustainable transmission line development. The following SD concepts are inherent to compact design: • Reduction in visual impact resulting from smaller, shorter towers, less vegetation clearing and smaller ROW. • Efficient land-use by increased power flow on relatively smaller ROW. • Reduction in electromagnetic field (EMF) resulting from smaller pole spacing. • Avoidance of land disturbance of important areas like sensitive habitats, farmlands and greenfield areas by use of existing (greyfield) ROW’s. • Reduced power losses resulting from increased voltages in a given ROW. This is not a comprehensive set of considerations for a SD transmission line design. The decision to apply a compact design to a given situation is commonly determined by the strong need to consider one or more of these aspects, although SD should be approached holistically considering all aspects of the design and sustainability. The following references are suggested for more information on SD in transmission line design [9–13].

References 1. EPRI Transmission Line Reference Book. 115–345 kV Compact Line Design (Blue Book). Palo Alto, California. Ed. (2008). www.epri.com 2. CIGRE Technical Brochure 792. Compact AC overhead lines. Working Group B2.63, Paris (2020, Feb). www.e-cigre.org 3. CIGRE Technical Brochure 831. Compact DC overhead lines. Working Group B2.62, Paris (2021, Mar). www.e-cigre.org 4. IEEE Power and Engineering Society. Technical report PES-TR62 “Guide for High Voltage Direct Current Overhead Transmission Line Design” (2018, Feb)

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5. Salimi, M., Barthold, L., Woodford, D., Gole, A.: Prospects for compaction of HVDC transmission lines. Paper 140 CIGRE-IEC Colloquium Montreal (2016, May). www.e-cigre.org 6. CIGRE Technical Brochure 416. Innovative solutions for overhead line supports (annex). Working Group B2.08, Paris (2010, June). www.e-cigre.org 7. Regis, O., et al.: Expanded bundle technique: the application of HSIL TL concept to increase capacity of overhead lines. CIGRE Paper 22-207, Paris Session (1998). www.e-cigre.org 8. Report of the World Commission on Environment and Development. Our common future. Transmitted to the General Assembly as an Annex to Document A/42/427—Development and International Cooperation: Environment. Brundtland Report (1987) 9. CIGRE Technical Brochure 147. High voltage overhead lines environmental concerns, procedures, impacts and mitigations. WG 22.14, Paris (1999, Oct). www.e-cigre.org 10. CIGRE Technical Brochure 265. Life cycle assessment (LCA) for overhead lines. WG B2.15, Paris (2004, Dec). www.e-cigre.org 11. CIGRE Technical Brochure 340. Utilities practices toward sustainable development. WG C3.03, Paris (2008, Feb). www.e-cigre.org 12. CIGRE Technical Brochure 383. Sustainable development performance indicators for transmission system operators. WG C3.02, Paris (2009, June). www.e-cigre.org 13. CIGRE Technical Brochure 548. Stakeholder engagement strategies in sustainable development—electricity industry overview. WG C3.04, Paris (2013, Aug). www.e-cigre.org

2

Electrical Parameters

Contents 2.1 2.2 2.3 2.4 2.5

Calculation of AC Resistance (R) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Calculation of Inductance (L) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Determination of Capacitance (C) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Surge Impedance (Z s ) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Corona . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 2.5.1 Audible Noise (AN) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 2.5.2 Radio Interference (RI) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 2.5.3 Losses . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 2.5.4 Ground Level Electric Field Effects . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 2.5.5 Rectification of Corona Problems . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .

10 10 11 12 13 15 17 17 18 20

Abstract

Compaction of overhead power lines influences, inter alia, the surface gradient of the conductor, resulting in corona-related effects. These include Audible Noise (AN) and the Radio Interference (RI). The Electric Field (EF) and Magnetic Field (MF) at ground level are also impacted. The regulatory limits for these parameters can become the governing factor for a compact line design. Additionally, for AC overhead power lines, compaction also affects the Surge Impedance Loading which impacts the ability of the line to transmit power. This chapter analyses how the design decision (e.g. conductor size, bundle configuration, phase to phase spacing, height, etc.) influence the electrical parameters that can affect the design limits and the power flow in AC lines.

© Springer Nature Switzerland AG 2024 R. Stephen and J. Iglesias (eds.), Compact Overhead Line Design, Compact Studies, https://doi.org/10.1007/978-3-031-44524-8_2

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2.1

Calculation of AC Resistance (R)

The resistance of a transmission line is described in detail in [1]. It is a function of the conductor construction and material and depends highly on the temperature. Therefore, it is not constant during the life of a line. In AC, the resistance increases due to the “skin effect”, a migration of the current towards the conductor surface. This effect increases with increasing conductor diameter. Frequency plays a lesser role at power frequency levels. For a normal range of conductors, the skin effect typically increases the resistance less than 2%, but this increment can be higher for larger conductors. In the case of steel-cored conductors (like the common ACSR conductors) the magnetic effects may produce an increment of the resistance. This increment is in general neglected, but, at high current densities, it may play a role for certain conductor constructions [2].

2.2

Calculation of Inductance (L)

The inductance is a function of the Geometric Mean Radius (GMR) and the Geometric Mean Distance (GMD) of bundle and phase geometry. GMR =

√ n n × r × R n−1

(2.1)

where r R n

0.7788 × radius of the conductor (m) Radius of the conductor bundle (m) number of sub-conductors

GMD =

√ 3 (d12 × d13 × d23 )

(2.2)

where d 12 d 13 and d 23

are the distances between the phases.

L = 2 × 10

L

−7

(

GMD × l × ln GMR

)

inductance of the line in Henrys per length l in meters.

(2.3)

2 Electrical Parameters

11

Thus, to decrease the inductance which will reduce losses and enable higher power transfer, the GMR should be large (to expand the bundle) and the GMD should be small (to reduce the phase distances).

2.3

Determination of Capacitance (C)

With reference to [3], the shunt capacitance of an overhead power line is affected by the earth plane which affects the field of the charged conductors. Line voltages are a function of the line charges. In steady state AC conditions, the relationship is given by [3]: [ ] (2.4) [Vi ] = Pi j × [Q i ] where Qi Pij

charge on the conductor per unit length are dependent on the geometry of the line as per equations below.

Pi'j = Pii =

1 × ln(Di' j /Di j ) 2π ε0

(2.5)

1 × ln(2h i /ri ) 2π ε0

(2.6)

where D' ij Dij ε0 hi ri

distance between conductor i and image conductor j (m) distance between conductors i and j (m) permittivity of free space (F/m) average height of conductors (m) radius of each conductor (m).

In simple notation [V ] = [P] × [Q]

(2.7)

To determine the currents in terms of voltages, the following matrix form relations hold: [I ] = jω × [P]−1 × [V ] = jω × [C] × [V ]

(2.8)

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R. Stephen and J. Iglesias

where [C]

is the capacitance matrix.

For C to be high, which is the intent if the aim is to increase the line SIL, then [P] needs to be small. Dij needs to be small. This implies that the phases need to be closer together to increase the C value. Similarly, the conductors need to be close to the ground to increase the C value.

2.4

Surge Impedance (Z s )

The surge impedance of the transmission line is defined as the square root of the ratio of the line inductance to the line capacitance [3]. √ ZS =

L C

(2.9)

where Zs L C

is the surge impedance is the series inductance and is the shunt capacitance.

The surge impedance loading (SIL) is the load at which the inductance and capacitance will negate each other and represents an indication of the capability of the overhead power line to transfer load. SI L =

(VL L ) 2 ZS

(2.10)

where V LL

is the line voltage.

It is desirable in most cases to increase the capability of the line to transfer load thus to increase C and reduce L to maximise this parameter. It is important to understand the parameters that make up the Resistance (R), the Inductance (L) and the Capacitance (C) of a transmission line. In summary, the SIL of a line can be altered by varying the bundle size and the phase spacing as well as the number of sub conductors in a bundle. The resistance of the line can be altered by the type of the conductor chosen as far as lay ratio and composition of the conductor is concerned. Homogenous conductors,

2 Electrical Parameters

13

or non-steel-cored conductors will not exhibit a variation of resistance as a function of current as will steel-cored conductors. Note that homogenous conductors will exhibit increased resistance due to temperature rise which may be because of current.

2.5

Corona

Compaction of HVDC and HVAC overhead power lines will increase the importance of corona-related limits to design issues, e.g. conductor size and configuration, pole-to-pole spacing, and suspension height. In illustrating this, it will be useful to briefly review the nature of corona. For HVDC the distribution of voltage between overhead transmission line conductors and ground is quite nonlinear, being the order of 20–27 kV/cm at the conductor surface and generally in the range from 10 to 25 kV/m at ground level. While conductors appear to be smooth, small irregularities such as scratches or contamination, can cause, with sufficiently high applied voltage, local surface gradients to exceed the voltage withstand capability of the surrounding air—thus causing very small, momentary, and local electrical breakdowns of the air (corona). Corona is sometimes visible at night with binoculars. Since both AC and DC corona discharges are a source of audible noise, conductor-to-conductor spacing must be large enough and/or applied voltage low enough to prevent noise levels at the Right of Way edge from exceeding certain criteria. Corona-based interference with AM band radio reception and, to a lesser extent, TV reception may also limit applied voltage for a given conductor configuration. The air that formed a path for a corona discharge is left ionized at the polarity of the conductor itself. With AC, ions which would normally be repelled by the conductor of like polarity, are drawn back to it on the succeeding half-cycle—thus are of no concern with AC overhead power lines. With DC they are repelled by the conductor of origin and either dispersed laterally from the Right of Way, neutralized by ions emanating from a pole of an opposite voltage, or flow to ground. Thus, a space charge environment is created consisting of a positive unipolar region adjacent to the positive pole, a negative unipolar region adjacent to the negative pole and a bipolar region between the two poles in which both positive and negative ions drift, mix and are partly neutralised through recombination. This space charge environment severely affects the electric field perception at the ground level. At any given point on the Right of Way ion density will vary over wide range even under seemingly identical weather conditions. While no adverse health effects have been found from ion flow to ground where people are present, high ion flow will exacerbate the annoyance effects of high ground-level electric field [4].

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The following factors affect the corona on a conductor surface [3]: • • • • • • • • •

System voltage Conductor diameter Clearances between conductor and adjacent phase/pole conductors Clearance between conductor and ground Number of conductors per phase/pole Bundle geometry (diameter of bundle of sub conductors) Conductor surface condition Atmospheric and weather conditions System frequency (AC).

As conductor diameter increases, the surface gradient decreases. However, when the conductor surface gradient exceeds the inception voltage the radio interference and audible noise levels will be higher than that of a smaller conductor diameter with the same surface gradient. According to [3], this phenomenon is caused by the fact that the rate of reduction of electric field with lateral distance away from the conductor decreases as the conductor diameter increases (Fig. 2.1). As phase to ground and phase to phase clearances increase, the surface gradient decreases in a complex way. Decreased air pressure also increases the surface gradient. Lines at high altitude (above 1000 m) will have higher corona activity given the same conductor diameter. The effect of the air pressure is quite marked as shown in Fig. 2.2. The corona inception voltage is not dependent on the number of conductors in the bundle and is calculated as if it is a single conductor irrespective of the bundle configuration [3].

INCEPTION VOLTAGE GRADIENT kV/cm

INCEPTION VOLTAGE vs DIAMETER 18.5 18 17.5 17 16.5 0.5

1

1.5 DIAMETER cm

Fig. 2.1 Inception voltage gradient versus conductor diameter

2

2.5

INCEPTION VOLTAGE GRADIENT

2 Electrical Parameters

24 22 20 18 16 14 12 10 0.6

15

INCEPTION VOLTAGE vs AIR DENSITY dia = 1cm

0.7

0.8

0.9

1

RELATIVE AIR DENSITY

Fig. 2.2 Inception voltage gradient versus air density

The second aspect that needs to be considered is the calculation of surface gradients. The design of the line needs to ensure that the ratio of the surface gradient to the corona inception voltage is < 0.95 [3]. To reduce the surface gradient of the conductor in the bundle it is necessary to increase the number of conductors in the bundle thus reducing the Eave and increasing the bundle radius to reduce Emax . The larger the conductor radius the lower the corona inception voltage but this effect is overshadowed by the increase in number of sub conductors in the bundle, the higher bundle radius and the larger phase/pole spacing. The surface gradient increases with smaller phase spacing and larger bundle size. It reduces with wider phase/pole spacing and increase in the number of sub conductor bundles.

2.5.1 Audible Noise (AN) The optimal minimum ratio for allowable corona performance Emax /Ec < 0.95 irrespective of the altitude chosen [3]. The audible noise limits that are typically recommended for outdoors according to [5] are as given in Table 2.1. Table 2.1 Sound levels recommended for outdoors in South Africa [5] Type of district

Daytime dBA

Evenings, weekends dBA

Night-time dBA

Rural

45

40

35

Suburban

50

45

40

Urban

55

50

45

Industrial

70

65

60

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R. Stephen and J. Iglesias

Audible noise limits will vary with location and are often aided by regional or local regulation. The limits provided above are an example of such regulations. The important factor to realise is that, depending on the background level of noise, the disturbing noise level which is defined as 7 dB above background noise may be exceeded. Thus, it is considered pertinent to design systems conservatively regarding corona. This is difficult to achieve if the line’s loading requirements are low relative to the system voltage as the aluminium area required is far smaller than the minimum area required considering corona design parameters. This normally leads to different alternatives being considered such as smaller conductors but more sub conductors in a bundle. Practical considerations need to be considered such as stringing of large bundles of small diameter conductors is problematic. Small conductors also tend to move more erratically in the wind. The physics governing positive and negative corona discharges differ, positive bursts having slower rates of rise and longer duration and, for that reason, being the dominant source of audible noise (AN) as well as radio interference (RI) adjacent to HVDC lines. Unlike AC lines, AN from DC lines is highest when conductors are dry. AN level is measured in decibels, adjusted for the normal hearing frequency spectrum, dBA. Allowable levels are generally governed by local noise codes, which, for overhead power lines are assumed to apply at the edge of the Right of Way while conductors are at rest. Fall-off of audible noise is generally rather gradual as illustrated in Fig. 2.3.

Fig. 2.3 Typical audible noise profile under an HVDC line

2 Electrical Parameters

17

Fig. 2.4 Typical radio noise profile under an HVDC line

The positive pole being the source of noise, the noise curve is offset by one half the pole-to-pole spacing. While audible noise is not normally a design constraint for HVDC lines, the likelihood of its being so increases slightly as compaction brings the Right of Way edge closer to the positive conductor.

2.5.2 Radio Interference (RI) During the era when AM radio predominated, RI from overhead power lines was a major design concern. RI has less an issue both due to reduction in popularity of AM broadcasting and because economics normally result in conductors large enough to prevent serious radio interference. If, by virtue of compaction, AC or DC lines are allowed to occupy ROW’s adjacent to highways or populated area, RI may become a more important design limitation, particularly since RI is much less sensitive to increases in conductor diameter than AN [6]. A typical lateral profile of radio interference (DC) is shown in Fig. 2.4.

2.5.3 Losses While compaction of overhead power lines may favour conductor configurations that offer less wind resistance and/or lower sag, those constraints are not likely to override the economic incentive to provide sufficient cross-section to keep losses at an acceptable level relative to transmitted power. An exception may be the case where High Temperature Low Sag (HTLS) conductors are used to take full advantage of their high-temperature tolerance. In this case, losses may be relatively high, mainly due to the higher resistance when operating at high temperatures. It must be noted, however, that, in meshed AC systems,

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R. Stephen and J. Iglesias

the operation of a line at high temperatures only occurs during limited periods of time (coincidence of high loads through the line and unfavourable weather conditions). In DC systems, the line load is usually set to a fixed maximum value and the periods of coincidence with unfavourable weather conditions may be higher.

2.5.4 Ground Level Electric Field Effects With either AC or DC, ground level electric fields, if too strong, will cause sensation to persons exposed to them—that sensation ranging from a slight tingling for weak ground-level fields to severe annoyance for very strong fields. For DC pole-to-pole voltage low enough to prevent corona on conductors, calculation of ground-level electric fields is quite straightforward and accurate. However even with relatively low levels of corona, some positive and some negative ions will eventually flow to ground under the conductor generating them, having two effects: (1) their presence distorts the ion-free distribution of voltage between conductors and ground—increasing the gradient felt by persons on the Right of Way and under the conductors, and (2) ions flowing to ground act as a constant current source, to which the human body presents a lower resistance path than the adjacent air, thus attracting a low level of current to ground. As a result, two factors are weighed in determining the level of annoyance for a given conductor configuration and applied voltage. • The electric field, in kV/m, at ground level as increased by field pattern distortion due to the presence of ions. • The ion current level flowing to ground in nanoamperes per square meter, absent the presence of an intervening path. To establish guidelines for levels low enough to minimize the prospect of human complaints, experts have recommended that electric fields at ground level not exceed E = 25 kV/m at ground level nor that ion current density exceed J = 100 nA/m2 [7]. However, these recommendations, if used, should be used with caution since they are not specific as to location, which season, nor what probability. Almost all HVDC operating lines have a reasonable probability of fields exceeding 25 kV/m during high humidity period in summer. Seasonal variations of the 50% probability level as measured on an 800 kV Chinese configuration are shown in Table 2.2 [8, 9]. The above-cited criteria of E ≤ 25 kV/m and J ≤ 100 nA/m2 were based on perception levels for humans exposed to positive of E and J densities within a confined test environment [9]. Values under an operating line will vary over a wide range based on DC operating voltage, weather, air density, and condition of conductors. Both ground level E and J, being dependent on ion flow, are affected by even slight wind currents. Thus, algorithms within predictive software attempt to predict E and J values that will not be exceeded a certain percentage of the time, either 5% or 10%, depending on the software used.

2 Electrical Parameters Table 2.2 Statistical results for ± 800 kV electric fields (kV/m) at ground level (50% likelihood)

19

Season

Time

Negative

Positive

Summer

2007/07

− 32

35

Winter Spring

2007/12

− 38

30

2008/01

− 27

18

2008/03

− 27

20

2008/05

− 25

23

Strict use of the above maximum E and J guidelines to judge the adequacy of a proposed DC configuration or upper voltage limit should be tempered by several considerations, specifically: • Several existing HVDC lines whose calculated E and J levels exceeds the guidelines have operated for many years without a history of complaints [10]. • The tests on which the above E and J criteria were based used positive field and ion current density since human perception of positive E and J levels have been shown to be at lower levels than for negative levels [11]. For example, in those tests a field of + 27 kV/m was necessary to produce a perception of level 3 (slightly annoying) while a − 36 kV/m was needed to provoke the same response. If that + 27 kV/m is reversed in polarity to − 27 kV/m, the perception level is just 1.7 where 1 is “just perceptible” and 2 is “definitely perceptible”. • Experience has shown that, for the same voltage magnitude, the negative pole results in substantially higher E and J levels than the positive pole. That has been clearly demonstrated by complaint experience on the Cahora Bassa ± 450 kV bipole line in South Africa—a bipole but with poles separated by about 1 km for security reasons. 533 kV operation of that line, which traverses densely populated areas, causes multiple complaints under the negative pole but not the positive. A similar negative pole dominance was noted under 500 kV lines of the Bonneville Power Administration in the US and under another 500 kV line built and operated by Furnas in Brazil [9]. Thus if, (1) criteria established for E and J are based on tests using positive field sensitivity tests, (2) negative fields have a significantly lower annoyance level, and (3) in the field, negative field levels significantly exceed positive levels, then application of those positive-based criteria to the (higher) negative fields will lead to pessimistic results. Perception threshold is not an issue for many new HVDC lines since other design constraints normally result in reasonably low ground level field effects. It is much more important in studies of converting HVAC line to HVDC where line parameters are fixed and where each incremental increase in allowable DC voltage translates into very large increments in the present worth of incremental transmission capacity [12, 13]. It will be of potential concern in design of compact HVDC lines as well, where lower profiles are sought.

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2.5.5 Rectification of Corona Problems Corona mitigation after the line is built is one of the most difficult aspects to rectify. This is because it requires either a reduction in system voltage or the use of additional sub-conductors which may not be possible without strengthening of the towers. It is critical to ensure that the bundle design caters for all weather and construction possibilities to ensure that the applicable audible noise limits are not exceeded. Some proposals to mitigate corona effects are shown below. There may be many other designs, measures or mitigation solutions that can be used depending on the specific line and needs. Underbuilt Groundwires Groundwires, suspended below the level of pole conductors may, in special cases, be useful to reduce ground level field effects or to allow higher voltage operation. That recourse will be helpful only in cases where conductor gradient is not a constraint. Its use will probably be limited to HVDC lines passing through areas of high public access or mountainous where low clearance is likely to be close to the towers rather than midspan. The minimum clearance to ground of such groundwires would have to correspond to the minimum fixed conductor-to-ground clearance, e.g. as prescribed by the US National Electrical Safety Code [14]. Recognizing the galloping and icedropping danger of conductors in the same vertical plan, under-built groundwires would have to be offset laterally from the pole conductors and large enough (or bundled) to prevent higher ground-wire gradients. To be effective, at least two such groundwires would be required under each pole. The effectiveness of such a recourse can best be demonstrated by the example bipole configuration illustrated in Fig. 2.5 in which, without underbuilt groundwires any voltage above ± 460 kV could be applied before the ground-level electric field gradient would exceed 25 kV/m. With two 25 mm groundwires suspended under each pole conductor, but offset from that pole’s centerline by 1 m, the voltage could be increased to 500 kV. To gain the same increase without groundwires, pole conductor clearance to ground would have to be increased by two meters. Ground-level electric fields and ion current density both at 460 kV without groundwires and at 500 kV with them are shown in Fig. 2.6. For typical current ratings the present worth of the additional transmission capacity achievable by that 9% boost on operating voltage is very high [12]. Potential Role of Asymmetry Unlike AC overhead power lines, the impact (or vulnerability) of DC lines differs for its two poles.

2 Electrical Parameters

21

Fig. 2.5 Example use of under-built groundwires

Pole Conductors Ground Wires

Number Diameter 2 4.5 cm 4 2.5 cm

Audible noise and radio noise both emanate from the positive pole. Pollution withstand is generally the order of 10% lower for the negative pole when disc insulators are used, withstand being close to equal on either pole if long-rod insulators are used [15]. Lightning, being predominantly negative, is often attracted to the positive pole. Anonymous flashovers, while still not thoroughly understood, are attributed to high gradients on the negative pole. As noted above, experience with ground-level field effects have shown stronger fields and ion current density under the negative pole (Table 2.3). Thus, assigning unequal voltages to two DC poles may accommodate one constraint while exacerbating another. However, where one issue clearly limits the degree of compaction possible, some level of asymmetry may be of advantage. For example, if field effects are the predominant limit in minimizing conductor height, an increase in positive voltage and drop in negative voltage may be an advantage, assuming of course that the increase in audible noise is acceptable and the lightning performance not materially affected.

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Fig. 2.6 Effect of underbuilt groundwires in allowing higher pole voltages Table 2.3 Effect of independent positive or negative voltage increase on performance issues of compact HVDC lines

Pole

Importance

+ Audible noise (AN)

XX

Radio noise (RN)

XX

Insulator W/S (with pollution)

Discs Long-rods

Lightning W/S

−

X =

=

X

Anonymous flashovers

X

Ground level field effects

X

2 Electrical Parameters

23

References 1. CIGRE Technical Brochure 345. Alternating current (AC) resistance of helical stranded conductors. Working Group B2.12, Paris (2008, Apr). www.e-cigre.org 2. CIGRE Technical Brochure 601. Guide for thermal rating calculations of overhead lines. WG B2.43, Paris (2014, Dec). www.e-cigre.org 3. Muftic, D., et al.: The Planning Design and Construction of Overhead Power Lines. S.L. Crown Publications (2005). ISBN 9780620330428 4. Sarma Maruvada, P.: Corona Performance of High-Voltage Transmission Lines. Research Studies Press Ltd., Hertfordshire (2000) 5. The measurement and rating of environmental noise with respect to annoyance and speech communication, SABS 60103. SABS, Pretoria (1993) 6. CIGRE Technical Brochure 388. Impacts of HVDC lines on the economics of HVDC projects. Joint Working Group B2/B4/C1.17, Paris (2009, Aug). www.e-cigre.org 7. CIGRE Technical Brochure 417. Technological assessment of 800 kV HVDC applications. WG B4.45, Paris (2010, June). www.e-cigre.org 8. Lu, J., Zehong, L., Yong, J., Jian, G., Jun, Y., Yong, Y., Guifang, W.: The progress on the electromagnetic environment study of HVDC transmission lines. In: The Second International Symposium on Standards for Ultra High Voltage Transmission 9. Blondin, J., Nguyen, D., Sbeghen, J., Goulet, D., Cardinal, C., Maruvada, P., Plante, M., Bailey, W.: Human perception of electric fields and ion currents associated with high voltage DC transmission lines. Bioelectromagnetics 17, 230–241 (1966) 10. CIGRE Technical Brochure 473. Electric field and ion current environment of HVDC overhead transmission lines. Joint Working Group B4/C3/B2.50, Paris (2011, Aug). www.e-cigre.org 11. Clairmont, B., Johnson, G., Zaffanella, L., Zelinger, S.: The effect of HVAC–HVDC line separation in a hybrid corridor. IEEE Trans. Power Deliv. 4(2) (1989) 12. Adapa, R., Barthold, L., Woodford, D.: Technical and economic incentives for AC to DC line conversion. CIGRE Paper 203, Paris (2010). www.e-cigre.org 13. CIGRE Technical Brochure 583. Guide to the conversion of existing AC lines to DC operation. Working Group B2.41, Paris (2012). www.e-cigre.org 14. National Electrical Safety Code C2-2007. IEEE 3 Park Ave., New York, NY 10016, USA 15. CIGRE Technical Brochure 518. Outdoor insulation in polluted conditions: guidelines for selection and dimensioning. Part 2 the DC case. Working Group C4.303, Paris (2012, Dec). www.e-cigre.org

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Insulation Coordination

Contents 3.1 3.2

Insulation Coordination for HVAC and HVDC Lines . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Overvoltages . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 3.2.1 Temporary (Sustained) Overvoltage . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 3.2.2 Slow-Front Overvoltage (Switching Surge) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 3.2.3 Fast–Front Overvoltage . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 3.3 Insulation Strength . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 3.3.1 Influence of Atmospheric Conditions . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 3.3.2 Statistical Behaviour of the Insulation . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 3.4 Insulation Coordination Calculation Procedure . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 3.4.1 For Continuous Voltage and Temporary Overvoltage . . . . . . . . . . . . . . . . . . . . . . . 3.4.2 For Slow-Front (Switching Surge) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 3.4.3 For Fast–Front . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 3.5 Insulation Coordination for Neutral Conductor (DC) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 3.6 Air Gap . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 3.6.1 For Sustained Overvoltage . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 3.6.2 For Slow-Front . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 3.6.3 For Fast Fronts . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 3.7 Example for AC Line . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 3.7.1 Power Frequency Insulation . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 3.7.2 Slow Front Insulation . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 3.8 Effect of Conductor Swing Due to Wind . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 3.8.1 Phase-to-Ground Gaps . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 3.8.2 Phase-to-Phase Gaps . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 3.8.3 Consideration of Asynchronous Swing . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 3.8.4 Application Example . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 3.9 Insulator Pollution Characteristics Under AC and DC . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 3.9.1 Principle of Insulator Dimensioning DC . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 3.9.2 Insulators for DC Lines . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . References . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .

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© Springer Nature Switzerland AG 2024 R. Stephen and J. Iglesias (eds.), Compact Overhead Line Design, Compact Studies, https://doi.org/10.1007/978-3-031-44524-8_3

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Abstract

This section describes the voltages and overvoltages that impact a transmission line, such as switching and lightning surges. It discusses the changes in the insulation stress and withstand characteristics due to compaction of overhead power lines, highlighting the differences in the insulation design between AC and DC overhead power lines and proposing some mitigation measures, like the placement of surge arrester devices. The AC system overvoltage stresses are the input of the insulation coordination study for the design of clearances and of the insulator chain of the AC overhead power lines. On the other hand, for DC lines these designs are usually determined by the pollution performance requirements. Note this is not a complete description of the insulation coordination process but describes the voltages and overvoltages that impact a compact transmission line.

3.1

Insulation Coordination for HVAC and HVDC Lines

The function of the insulation coordination process is to choose the optimal dielectric strength of the overhead power line in order to ensure the handling of voltages and overvoltages appearing during operation while considering any overvoltage protection and taking into account an acceptable failure rate. For the insulation coordination, a distinction has to be made between AC and DC overhead power lines. The insulation design of existing AC overhead power lines is generally dominated by the performance with regard to slow-front (switching) overvoltages or lightning overvoltages, which determine the arcing distance of the insulator strings. For a given insulator length, the pollution withstand requirements are then normally satisfied by selecting insulators with a suitable creepage factor (i.e. creepage distance per unit of insulator length). In almost all cases, except perhaps for locations with the highest pollution severity, this can be achieved with commonly available insulator designs. In DC systems the slow-front overvoltage levels are generally rather low, and the insulation design is often dominated by pollution performance requirements. Considering the restricted space available for the insulators on compact HVDC lines, it is necessary to limit as far as possible the uncertainties in insulator selection and dimensioning by following a detailed design approach.

3 Insulation Coordination

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Fig. 3.1 Comparison of indicative insulation distance requirements with respect to switching overvoltages (blue), lightning overvoltages (red) and pollution (green) for AC/DC systems [1]

The importance of the design and selection of insulators with respect to pollution is illustrated in Fig. 3.1 which shows a comparison of the indicative insulation lengths required for HVAC and HVDC systems to withstand lightning and switching overvoltages, as well as the effects of insulator pollution [1]. It is apparent from Fig. 3.1 that in HVAC systems the insulation lengths are in most cases determined by either switching or lightning overvoltages. In contrast, the situation for HVDC systems is quite different. Firstly, the creepage distance required for DC at a particular site severity is higher than for AC, and secondly, the magnitude of slow-front transients is generally lower than those occurring in AC systems. In areas with significant pollution this may require large insulator dimensions, which may influence, and in some cases dictate, the conceptual design of the whole HVDC line project. Choices that may be impacted are: • The routing of the line and siting of the converter stations to avoid polluted conditions. • The use of cables instead of overhead power lines to minimize the number of external insulation surfaces exposed to pollution. • Utilizing indoor switchyards and converter stations to protect the external insulation surfaces from pollution and/or wetting. • The choice of insulator assemblies or conductor configurations for the transmission line, or special layouts of the converter stations, to accommodate long insulator dimensions or special insulation solutions [1].

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An inappropriate design for pollution conditions can therefore have a strong impact on the overall system cost as it may result in higher investment costs (i.e. the need for extremely long and costly substation insulators, or taller towers to accommodate long insulator strings), or increase the operating costs (e.g. the need for costly palliative maintenance measures). It is therefore necessary for the DC case to limit, as far as possible, the shortcomings in the design process by following a detailed design approach. This explains why a simplified approach, with its potential risk of over- or under-design, is not advised for HVDC systems. This contrasts with AC systems where a simplified approach can be used with confidence in all environments except for areas with particularly severe pollution levels [1].

3.2

Overvoltages

The overvoltages can be classified as [2]: • Sustained voltage: continuous power frequency voltages originated from system operation under normal conditions; and temporary sustained overvoltage originated from switching operations like load rejection, energization, and resonance conditions. • Slow front overvoltage (switching surges): initial part or the transient due to switching operations, and from faults • Fast front overvoltage: originated mainly from lightning strikes or certain types of switching • Very fast front overvoltage: mainly related with gas insulated substation equipment switching.

3.2.1 Temporary (Sustained) Overvoltage These overvoltages are of a sinusoidal type and defined by its magnitude and duration. They affect the insulation withstand of the clearances (gaps) and other insulation considerations. These can be defined by test with an amplitude with duration of one minute. They are also important for examining the surge arrester behaviour and its energy absorption. The surge arrester rating is chosen not to conduct significant current during this overvoltage. Due to the intrinsic control of conventional DC converters, temporary overvoltages are low and need normally not be considered regarding line insulation. Higher temporary overvoltage levels may however occur with certain VSC-based converter configurations during DC line-to-ground faults. However, such overvoltages are of short duration and the magnitude is usually kept well below 2 p.u. by the DC surge arresters [3].

3 Insulation Coordination

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The origins of temporary overvoltage are earth faults, load rejection, line/ equipment switching and resonances: • Earth faults. This overvoltage is related to phase-to-ground faults location and the system neutral earthing. For ungrounded earthing system the phaseto-ground overvoltage may reach values close to the phase-to-phase voltage. For grounded neutral impedance or solidly grounded system these overvoltages are much smaller. • Load rejection. For long line systems, after load rejection an overvoltage appears due to the Ferranti effect, they are bigger in the open end of the line. Shunt reactors connected to the lines reduce this overvoltage. The condition may become worse if load rejection is combined with pre-existing, or post occurring phase-to-ground faults. • Line/equipment switching. Energization and reclosing of lines lead to temporary overvoltage due to the Ferranti effect. Shunt reactors reduce the overvoltage. Capacitor switching in is also a cause of temporary overvoltage. • Resonances. Temporary overvoltages, are originated also by resonances and may be mitigated by detuning the system circuit. Transformer energization and Ferro-resonance should be of concern.

3.2.2 Slow-Front Overvoltage (Switching Surge) Slow front overvoltage is of oscillatory nature fast damped. They are represented in laboratory test by a wave with time-to-peak of 250 μs and time to half-value end the tail 2500 μs. When single pole-to-ground faults occur on bipolar DC lines, transient overvoltages are superimposed on the DC voltage of the healthy pole conductor and on the neutral conductor, if present. The overvoltage magnitude depends on the position along the line, the location of the fault, and the surge reflection properties of the line terminal equipment. The resulting pole-to-ground overvoltages have similar characteristics in terms of magnitude and wave shape as slow-front overvoltages in AC systems. The maximum magnitude, occurring for fault locations at the midpoint of the line, is usually below 1.8 p.u. for conventional DC systems [4]. Different terminal equipment or novel converter configurations, e.g. in VSC-based systems, may require special studies to determine the overvoltage profile. They arise from line energization, line reclosing (re-energization), fault inception, fault clearing, load rejection, capacitive switching, or inductive load switching: • Line energization. During line energization, a slow-front overvoltage occurs super imposed to the power frequency overvoltage. When the breaker closes, a travelling wave moves along the line, creating a slow-front overvoltage (after some reflections/refractions).

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The peak value of the overvoltage depends on the point-on-wave switching instant, and the Ferranti effect influenced by the presence of shunt reactors. The overvoltage may be mitigated by synchronized switching or by the use of pre-insertion resistors. When pre-insertion resistors are present, the transient phenomena have two components: one when the resistor is inserted; and another when it is bypassed. The resistor insertion time average value is specified (about 10 ms) but there is a random variation of a few milliseconds (2–4 ms). Synchronized switching also has a random behaviour as related to closing instant. These energization overvoltages are determined by simulation with electromagnetic transient model software running a set of 100–200 cases (shots) characterized by the switching closing instant in the three phases. It is assumed that the resistor insertion instant follows a Gaussian distribution defined by mean value and standard deviation. As result, the maximum value of the overvoltage is determined (and the corresponding switching closing instants) and a set of voltage value in the sending, receiving and some intermediate distance of the line. The values are used to define a statistical distribution of overvoltage (Gaussian or Weibull) through a mean, a standard deviation, and a truncated maximum value. There are two ways for establishing the distribution of overvoltage: called “phase-peak” and “case-peak” methods. In the former for each shot, for one location, the peak value of the three phases are included in the distribution; in the latter, only the highest of the three phase peaks is included in the distribution. Therefore, they should be considered in different ways when designing the insulation. Energization over an existing phase-to-ground fault may lead to higher overvoltage; however, they are not used for line insulation design but only to checking surge arrester performance. It should be noted that phase-to-ground and phase-to-phase overvoltage distribution shall be obtained for insulation design. • Reclosing. After line opening, one or more attempt of re-energization may occur automatically. When the line is disconnected a trap charge is kept in the line (In the line capacitance) so the reclosing is an energization over the residual voltage of the line; this should lead to higher slow-front overvoltage than for energization. For lines without shunt connected reactors the trapped charge is a DC voltage with certain damping (due to line conductance). For lines with shunt reactors the DC voltage is of oscillatory nature (with two frequencies superimposed, a combination due to the natural line frequency and the operating voltage frequency). In studies, the worst instant of breaker contact closing shall be determined. After that, a statistical calculation around this worst position is done (random contact closing instant).

3 Insulation Coordination

• •

•

•

31

The reclosing overvoltages are mitigated by using pre insertion resistors in the breakers or synchronized closing system. The trapped charge can be controlled through: open resistor in the breaker; shunt reactor; inductive potential transformer and by closing/opening a line to ground fast switch. The phase-to-ground and phase-to-phase overvoltage distributions are searched to be used in the insulation coordination, in a similar way as for the energization overvoltage. Load rejection. Apart from the sustained overvoltage in the initial cycles there may occur slow-front overvoltages, in general lower than those for energization or reclosing. Fault application. When a fault occurs, a travelling wave goes in the line and may cause high overvoltage in points of discontinuities (different surge impedances) or when summing up waves from different passes. In general, this overvoltage has short shape and is discharged by surge arrester without any high energy content. Sometimes they are treated as fast-front surge. Fault clearing. They are in general lower than energization or reclosing overvoltage and they depend on the type and distance of the fault, breaker sequence of opening, and prior network condition. Opening resistor may be used to mitigate them. Inductive and capacitive load switching. Capacitive load switching does not lead to overvoltage; overcurrent is therefore of concern. Inductive load switching off may cause local overvoltage when the breaker forces the current to zero before natural zero crossing. Transformer energization may cause high inrush current that could lead to resonance in points of the system. This type of overvoltage, in general, does not influence line design but substation design. Mitigation is obtained with closing/opening resistor or synchronized switching.

3.2.3 Fast–Front Overvoltage Fast-front overvoltage is due mainly to lightning surge. They are represented by a standard impulse wave of 1.0/50 μs. Lightning can strike the groundwires, or the phase conductors or the ground. When striking the conductor, called direct stroke, the overvoltage generated from phase-to-ground is very high, proportional to the stroke current magnitude and the phase conductor surge impedance. A shielding failure describes when a lightning strike bypass groundwires with a direct stroke to the conductors. If the lightning strikes the groundwire, the current flows through them and to the ground by the tower, generating an overvoltage from the groundwire to ground. This overvoltage is coupled to the phase conductors leading to an overvoltage across the insulation that can create a failure (back flashover).

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Lightning striking the ground near the line may induce overvoltage in the lines, that in general are lower than 500 kV, therefore not important for high voltage overhead power lines (> 138 kV). Lightning overvoltage failures are reduced by the following actions: • Installation of (in general two) groundwires or improving shielding effect (reduces direct flashover) • Reducing tower footing resistance by installing counterpoise, (reduces back flashover). • Increase in the insulation (reduce direct and back flashover) Methods for calculating fast-front overvoltages on AC overhead power lines are described in [5]. The procedures are essentially the same for DC lines, with the following exceptions: • Lightning currents injected by direct strikes to a DC pole conductor generates transient overvoltages which are superimposed on the DC service voltage. Thus, the composite overvoltage occurring between the conductor and the tower varies depending on the magnitude and polarity of the lightning current and the polarity of the DC voltage. • When lightning currents are injected to towers or groundwires, the overvoltages occurring between the DC conductors and the tower depend on the magnitude and polarity of the lightning current, and the polarity of the DC conductor [3]. Also, it has to be considered that compaction is a reduction of vertical and horizontal distances, which reduces exposure to lightning strikes.

3.3

Insulation Strength

The overvoltage withstand characteristics of a compact line can be divided into: • Tower top and midspan clearances, primarily associated with the performance of the line. • Clearances between the conductors and objects on the ground, primarily associated with personal safety. As discussed above, overvoltages on DC lines are generally composed of transient voltages superimposed on the DC service voltage. However, the withstand of air gaps is only marginally affected by the presence of the DC voltage bias, suggesting that the total composite overvoltage across the air gap may be used for determination of required clearances with regard to fast-front and slow-front overvoltages. The same can be said for the air gap across insulators, except in wet conditions where the slow-front overvoltage withstand is reduced by about 15% [3].

3 Insulation Coordination Table 3.1 Voltage standard tests [6]

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Sustained overvoltage

1 min

Sinusoidal wave

Fast-front

1.2/50 μs

Waveform

Slow-front

250/2500 μs

Waveform

The use of Transmission Line Arrester (TLA), placed in the line towers, e.g. in the midpoint of the line or in a section of the line, can reduce the overvoltages and the insulation levels on both AC and DC lines. When a low voltage stress is applied in insulation (insulator or air gap) there is no flow of current. When this stress is increased to a sufficient level, the resistivity along the path through the insulation changes to a low value conducting current (breakdown). Several factors influence the dielectric strength of the insulation [2]: • • • • •

The magnitude, shape, duration, polarity of the voltage applied The electric field distribution in the insulation The type of insulation: air, liquid, solid, gas The physical state of the insulation (including ambient conditions) Breakdown in air insulation is strongly dependent on gap configuration and polarity and of the wave shape of the voltage stress.

The withstand capability of insulation is determined through applied voltage standard test [6] (Table 3.1). Withstand capability is different depending on the wave polarity.

3.3.1 Influence of Atmospheric Conditions The insulation withstand depends on the ambient conditions, and they are referenced to as “standard atmospheric conditions”: • Temperature: 20 °C • Pressure: 101.3 kPa (1013 mbar) • Absolute humidity: 11 g/m3 . After defining the desired withstand for standard condition a correction must be applied to match the local atmospheric condition ensuring the withstand capability of self-restoring insulation.

3.3.2 Statistical Behaviour of the Insulation Some insulation materials are non-regenerative (oil, paper in a transformer for instance) and others are auto-regenerative like the air. In the latter case the statistical behaviour is discussed here-in-after.

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When a certain number of shots or impulses with the same wave are applied in an insulation material the breakdown may occur by only some of the impulses. Due to this, the insulation withstand is defined by a probability function (Gaussian or Weibull). The statistical behaviour of the insulation (as a Gaussian distribution) is defined provided two values are known, for instance, the mean U 50 , and the standard deviation Z = U 50 – U 16 . Sometimes the value U 50 is substituted by U 10 or U 2 . The conventional deviation can be assumed as: • For fast-front (lightning): Z = 0.03 U 50 • For slow-front (switching surge): Z = 0.06 U 50 . IEC 71-1 Standard [7] considers the value U 10 = ( U 50 – 1.3 Z), to define the withstand capability of equipment insulation.

3.4

Insulation Coordination Calculation Procedure

3.4.1 For Continuous Voltage and Temporary Overvoltage The coordination is set based on the maximum voltage peak value √ phase-to-ground at power frequency that is the phase-to-phase voltage divided by 3. Insulation withstand of insulator string varies depending on the pollution level. Reference [7] indicates the specific creepage (mm/kV), to set the recommended distance depending on the pollution level. The distance refers to the contour of the insulator (creepage distance). As example for pollution level “light” the recommendation is 16 mm/kV (rms, phase-to-phase) or 27.7 mm/kV (rms, phase-to-ground).

3.4.2 For Slow-Front (Switching Surge) There are two methods: deterministic; and statistical approaches. In the deterministic approach a statistical value of the overvoltage is set equal to a statistical value of the withstand (both with certain probability). U S50 + N S Z S = UW 50 − N W Z W where U S50 , Uw50 are the means of the overvoltage and withstand capability Z S , Z w are the standard deviations (overvoltage-withstand)

(3.1)

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N S , Nw are number corresponding to a desired probability or the truncation points. Note that sometimes N S = 2 is chosen to set the overvoltage with 2% probability of being exceeded and N W = 1.3 to set the withstand to 10% not to be exceeded. In the statistical approach the risk of failure is evaluated. The following assumptions are established: • Peaks other than the highest are disregarded. • Shape is taken as identical to the standard waveform. • All overvoltage of the same polarity (the worst). The risk is then calculated as ∫U 2 R = f(u) P(u) du

(3.2)

U1

where f(u) P(u) U1 U2

probability density of the overvoltage discharge probability of the insulation truncation point of the discharge probability. truncation point of the overvoltage

A simplified approach consists of the assumption that the overvoltage (U S50 , Z S ) and discharge voltage (Uw50 , Z w ) are Gaussian curves. Failure occurs when the overvoltage is greater than withstand. The combination is also a Gaussian in which the mean (R50 ) and the standard deviation (Z R ) are: R50 = U S50 − UW 50 ZR =

√

2 Z S2 + Z W

1 Risk = 1 − √ 2π X=

(3.3)

∫0

(3.4)

1

e− 2

( 2) x

dx

(3.5)

−∞

x − R50 ZR

(3.6)

When there are n equal insulations stressed by the same overvoltage, the global risk of failure of at least one insulation (R), is: R = 1 − (1 − R1 )n

(3.7)

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where R1 is the individual risk This must be done for the gaps in the three phases of one tower then extended to all towers in the line.

3.4.3 For Fast–Front The same concepts applied for slow-front are valid. However, in general, no extra isolation than for slow front is provided for fast surge. The isolation provided for slow front is that used for lightning performance evaluation outages per 100 km per year.

3.5

Insulation Coordination for Neutral Conductor (DC)

HVDC lines may be equipped with a neutral conductor (metallic return) if a transition from bipolar to monopolar operation cannot use ground return. The neutral conductor is shared between the two poles and is electromagnetically coupled with both; a fault in one DC pole may cause a fault of the neutral insulation and affect the operation of the other pole. Thus, faults of the neutral insulation will affect pole independence unless they are efficiently detected and cleared. The neutral insulation must withstand the continuous operating voltage on the neutral conductor, the system start-up overvoltages, the system shut-down overvoltages, and the overvoltages that occur during commutation failure. A neutral insulator string comprising two to five units, or a composite insulator of corresponding length, would typically satisfy these requirements. However, the neutral insulator must be much longer than that to withstand both slowfront overvoltages due to pole-to-ground faults, and fast-front overvoltages caused by lightning. The neutral insulation strength of originally designed DC lines is typically lower than the pole insulation strength, and consequently, the neutral insulation is more susceptible to flashovers (including back flashovers). If the converted line needs to have a dedicated neutral conductor, its insulation must be carefully designed in order not to reduce the reliability of the line. Further information on insulation coordination for the neutral conductor can be found in [3].

3.6

Air Gap

The air gaps, filled or not with insulators, are of the self-restoring type. The geometrical configuration of the gap influences their withstand capability. Requirements on tower top and midspan clearances for AC lines are given in [8] based on [9]. When using a deterministic approach, the same requirements may be applied for checking the clearances of the DC line, while considering the

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composite overvoltages discussed above. Alternatively, a statistical approach may be used to calculate the performance of the DC line by considering the composite overvoltage stresses, the withstand characteristics, and the rate of overvoltage occurrences. The required safety clearance to objects on the ground is governed by national codes. Requirements are usually based on the relation between the flashover voltage of the insulators and the flashover voltage of the safety clearance. If it is conservatively assumed that both fast-front and slow-front overvoltages are limited by flashovers across the line insulators, the required safety clearances for fast-front and slow-front overvoltages can be expressed in relation to the insulator striking distance by applying the appropriate gap factors for the respective air gaps and overvoltage types. However, slow-front overvoltage levels of DC lines are often low enough to prevent insulator flashovers, suggesting that only fast-front overvoltages need to be considered for determination of safety clearances [1]. The critical flashover value (U 50 ) in kV for “standard atmospheric condition”, can be estimated as function of the gap distance (d) in meters by the equations in the following sections:

3.6.1 For Sustained Overvoltage The withstand characteristic is shown in Fig. 3.2.

Fig. 3.2 Withstand characteristic of gap (power frequency)

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3.6.2 For Slow-Front For phase-to-ground gaps the following equations applies: U50 = k 500 d 0.6 ; 2 < d < U50

(3.8)

3400 ; 5 < d < 15 1 + 8/d

(3.9)

Or V50 = k

k being the gap factor as shown in Table 3.2. For phase-to-phase insulation other values of k applies. Phase-to-phase insulation is influenced by the ratio α, defined as the ratio of the negative peak and the sum of the positive and negative peaks Fig. 3.3 (Table 3.3).

3.6.3 For Fast Fronts For fast fronts the gap factors are: U50 = k + 500 d

(3.10)

where k + = 0.74 + 0.26 k k is the gap factor for slow-front.

3.7

Example for AC Line

Consider a 500 kV line (maximum sustained voltage during line energization of 600 kV), 200 km, average span = 500 m, therefore 400 towers.

3.7.1 Power Frequency Insulation Assuming a “light” pollution level in the line region, thus a specific creepage distance of 16 mm/kV results in the necessary insulator string creepage distance of 16 × 600 = 8800 mm. Assuming a 280 × 170 mm insulator which has a creepage distance of 380 mm, the necessary number of insulators = 8800/380 ≈ 24 insulators in a string with length of 24√× 170 = 4080 mm. The air gap should withstand 600 √2 = 490 kV. From Table 3.2 the air clear3 ance should be ≥ 1.0 m (to be preserved even with conductor swing due to wind of return period say 50 year; or 40–50° swing angle). Similarly, the phase-to-phase air clearance should be ≥ 1.7 m.

3 Insulation Coordination Table 3.2 Gap factor for slow-front (with and without insulator filling the gap)

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Table 3.3 Gap factor (k) for phase-to-phase insulation Configuration

α = 0.5

α = 0.33

Ring-ring or large smooth electrodes

1.80

1.70

Crossed conductors

1.65

1.53

Rod-rod or conductor-conductor (along the span)

1.62

1.52

Supported busbars (fittings)

1.50

1.40

Asymmetrical geometries

1.45

1.36

Fig. 3.3 Phase to phase overvoltage

3.7.2 Slow Front Insulation Minimum air clearance As an example of this type of calculation, the line energization overvoltage to ground and phase-to-phase was calculated for a system above mentioned. The calculation was done with an EMT software applying 200 shots determining the distributions (mean and standard deviation) in all phases and within phases in 5 position in the line (beginning, 25, 50, 75%, and end from the energization terminal). Table 3.4 shows the risk calculation values considering the phase-to-ground CFO (critical flash over) U W50 = 915 kV and phase-to-phase CFO U W50 = 1630 kV. To reach a certain level of risk about three values of CFO can be applied for interpolation or using a trial and error interactive process in a spreadsheet (here, the latter process was used to get the CFO values above). The phase-to-ground risk in a line position is the sum of the risks in the three phases, similarly the phase-to-phase risk. These risks are plotted in Fig. 3.4. The risk of failure for all the line is obtained by integrating the values in Fig. 3.4 or simply dividing the line by sections of 5–10% of the length. The results are in Table 3.5. The risk above matches the desired risk 1E−03 and 1E−04 for phase-to-ground and phase-to-phase.

3 Insulation Coordination

41

Table 3.4 Line energization risk calculation Over. mean (U S50 ) kV Send

25%

50%

75%

End

Overv. dev (ZS ) kV

R50 = U S50 − U W50 kV

Zr kV

Risk p(x) ≤ 0

Phase A

516.0

28.1

− 399.0

61.7

4.9088E−11

Phase B

572.4

26.7

− 342.6

61.1

1.0063E−08

Phase C

547.1

36.9

− 367.9

66.2

1.3468E−08

Phase A–B

897.7

35.0

− 732.3

103.9

9.0183E−13

Phase B–C

983.5

51.5

− 646.5

110.5

2.4608E−09

Phase A–C

903.9

60.3

− 726.1

114.9

1.3074E−10

Phase A

530.3

32.4

− 384.7

63.8

8.0083E−10

Phase B

589.1

29.5

− 325.9

62.3

8.4721E−08

Phase C

563.8

40.9

− 351.2

68.5

1.4642E−07

Phase A–B

914.5

36.8

− 715.5

104.5

3.7725E−12

Phase B–C

1006.3

55.0

− 623.7

112.2

1.3525E−08

Phase A–C

926.3

65.7

− 703.7

117.8

1.1650E−09

Phase A

547.5

35.4

− 367.5

65.3

9.2883E−09

Phase B

610.7

31.3

− 304.3

63.2

7.3933E−07

Phase C

583.0

42.1

− 332.0

69.2

7.9525E−07

Phase A–B

936.5

39.8

− 693.5

105.6

2.5556E−11

Phase B–C

1039.8

60.5

− 590.2

115.0

1.4332E−07

Phase A–C

948.4

68.1

− 681.6

119.2

5.3321E−09

Phase A

554.8

35.6

− 360.2

65.4

1.8477E−08

Phase B

620.9

33.2

− 294.1

64.2

2.2848E−06

Phase C

588.3

43.1

− 326.7

69.8

1.4311E−06

Phase A–B

952.9

43.9

− 677.1

107.2

1.3424E−10

Phase B–C

1057.8

64.3

− 572.2

117.0

5.0429E−07

Phase A–C

956.9

70.7

− 673.1

120.7

1.2150E−08

Phase A

556.9

37.5

− 358.1

66.5

3.5631E−08

Phase B

620.9

33.6

− 294.1

64.3

2.4382E−06

Phase C

589.5

43.6

− 325.5

70.1

1.7333E−06

Phase A–B

952.4

45.0

− 677.6

107.7

1.5471E−10

Phase B–C

1057.8

63.8

− 572.2

116.8

4.7628E−07

Phase A–C

955.3

70.8

− 674.7

120.7

1.1457E−08

The next step is the determination of air gaps (d) to match the calculated phaseto-ground CFO 915 kV and CFO phase-to-phase 1630 kV. CFO = k 500 d 0.6 With k being the gap factors. Table 3.6 shows the phase-to-ground values of gap d.

(3.11)

42

R. Stephen and J. Iglesias

phase-ground

log(risk)

phase phase 0 -1 0 -2 -3

0,1

0,2

0,3

0,4

0,5

0,6

0,7

0,8

0,9

1

-4 -5 -6 -7 -8 -9 -10 -11 -12 -13 -14 distance %

Fig. 3.4 Risk versus distance Table 3.5 Risk by section and total Nr. of towers

Line dist. pu

Risk ph-g

Log (risk) ph-g

Risk ph–ph

Log (risk) ph–ph

40

1

4.21E−06

− 5.38E+00

4.88E−07

− 6.31E+00

40

0.9

4.17E−06

− 5.38E+00

6.31E−07

− 6.20E+00

20

0.8

3.98E−06

− 5.40E+00

6.31E−07

− 6.20E+00

20

0.75

3.73E−06

− 5.43E+00

5.17E−07

6.29E+00

40

0.7

3.16E−06

− 5.50E+00

3.98E−07

− 6.40E+00

40

0.6

2.51E−06

− 5.60E+00

2.51E−07

− 6.60E+00

40

0.5

1.54E−06

− 5.81E+00

1.49E−07

− 6.83E+00

40

0.4

1.00E−06

− 6.00E+00

7.94E−08

− 7.10E+00

20

0.3

5.01E−07

− 6.30E+00

3.98E−08

− 7.40E+00

20

0.25

2.32E−07

− 6.63E+00

1.47E−08

− 7.83E+00

40

0.2

1.58E−07

− 6.80E+00

1.00E−08

− 8.00E+00

40

0.1

5.01E−08

− 7.30E+00

5.01E−09

− 8.30E+00

0

0

2.36E−08

− 7.63E+00

2.59E−09

− 8.59E+00

Total (400)

8.41E−04

1.04E−04

3 Insulation Coordination

43

Table 3.6 Values of air gap

k

d (m)

Conductor window

1.15

2.17

Conductor to tower

1.35

1.66

Conductor to guy wire

1.40

1.56

Conductor to 4.5 m object

1.35

6.16

Fig. 3.5 Phase-to-phase overvoltage (α = 0.5)

Related to phase-to-phase, IEC 71-2 [6] indicates the gap factor to be used in the calculation as function of α = V−/(V++ V−). Figure 3.5 shows the worst case phase-to-phase overvoltage calculated. The value of α is near 0.5 and for this the gap factor is 1.62. Others case may lead to lower values of α. For α = 0.33 the gap factor is 1.52, therefore the phase-to-phase distance shall be about 3.57 m.

3.8

Effect of Conductor Swing Due to Wind

3.8.1 Phase-to-Ground Gaps The gap distances determined with the procedure described above should be preserved even in the presence of wind. For the sustained voltage insulation, the gap is preserved even with a wind with return period of for example 50 years. For slow front insulation small swing (say 10°, or wind with return period of 2 years) or no swing is adopted.

44

R. Stephen and J. Iglesias

3.8.2 Phase-to-Phase Gaps When there is a tower between phases the phase-to-phase gap requirement is matched by the designed phase-to-ground gaps. In case that the distance between phases is filled with air some designs consider the possibility of asynchronous conductor swing and extra distance in the necessary phase-to-phase gap is added as described below.

3.8.3 Consideration of Asynchronous Swing According to [10] the clearances between conductors and earthed tower elements and between phase conductors vary in conformance with wind actions. The wind actions themselves vary with time and location and can be described as randomly distributed using statistical approaches. The phase-to-phase clearances are determined by the formulas presented in [10]. However, for adjacent phases, as in the case of horizontal configurations, it is necessary to prove that the middle span clearances together with power– frequency voltages do not cause flashover under the occurrence of asynchronous swing angles. The swing angles are calculated by: (

(ρ/2) · C x · V R2 · G L · a · d · n θ = ar ctan n· p·a

) (3.12)

where ρ Cx VR GL a d n p

air density depending on temperature, humidity and altitude above sea level (equal to 1.225 kg/m3 , at standard conditions), (kg/m); drag factor equal to 1,0 for standard conductors; reference wind velocity (m/s); span factor taking into account the effect of span length equal to (0.6 + 80/ a) according to EN 50341-3-4; wind span (m); conductor diameter (m); number of sub-conductors; effective conductor weight taking into account the differences in the level of conductor attachment points (N/m).

Considering the calculated swing angle, possible differences between swing angles of neighbouring phases are considered with a probability lower than 98%. For this limit the conductors may deviate between themselves with the following swing angles:

3 Insulation Coordination

45

Conductor 1: θ 1 = θ + 2σ Conductor 2: θ 2 = θ − 2σ. where [ ( )] σ = 2.25 1 − ex p −V R2 /230

(3.13)

3.8.4 Application Example Consider a 500 kV line (Vmax = 525 kV), using cross-rope or Donau towers, without metallic parts between phases in a horizontal configuration. The separation between phases is 6.2 m in the typical tower, which will be examined in this approach. The data used in equations above are: ρ = 1.225 kg/m3 ; C x = 1.0; V R = 32.44 m/s; a = 500 m; GL = 0.6 + 80/500 = 0.76; d = 0.02445 m; n = 4; p = 9.5863 N/m. The conditions of swing angles of conductors were determined and analysed as follows. For the wind speed corresponding to power frequency voltages (V R = 32.44 m/ s), the following swing angles and standard deviations have been determined by equations above: θ = 51.34°; σ = 2.23 Therefore: θ 1 = 55.8° θ 2 = 46.9° For the wind speed corresponding to switching surges (V R = 19.46 m/s), the following swing angles have been determined: θ = 24.17°; σ = 1.82° Therefore: θ 1 = 27.8° θ 2 = 20.6°. The minimum electrical distance between phases for the power frequency conditions should be 1.7 m and for switching surge 3.6 m as determined above in this section:

46

R. Stephen and J. Iglesias

Fig. 3.6 Asynchronous swing of the conductors at the mid span position

The asynchronous swing of conductors is a rare phenomenon, and it is not necessary to consider electrical distances higher than the ones needed for power frequency voltages, thus meaning that the probability of asynchronous swing simultaneously occurring with switching surges or lightning overvoltages is very low, so that if such overvoltages were considered, there would be an unnecessary increase in the project costs. Figure 3.6 shows the electrical distances obtained when considering asynchronous swing in the conditions of power frequency and switching surge overvoltage. It has been conservatively considered the conductor sag at EDS condition for a 500 m span length. It can be observed that for power frequency condition the distance obtained is higher than the minimum 1.7 m (for two wind conditions). Therefore, it can be concluded that the existing phase distance of 6.2 m is sufficient for the correct operation of the line.

3 Insulation Coordination

3.9

47

Insulator Pollution Characteristics Under AC and DC

If AC and DC lines are operating in the same pollution environment, the actual level of pollution on the DC insulators will in most cases be higher than on the AC insulators. This difference may be up to 3 times depending on environment. The approach for taking this into consideration in the dimensioning process is described in the IEC standard 60815 [11]. Other references [12–16], show that an insulator with the same level of pollution will have a lower flashover strength under DC voltage than under the corresponding AC voltage. The ratio of DC (peak) to AC (r.m.s.) flashover voltage varies depending on pollution level and is influenced by many factors, but it typically falls in the range 100–60% for the same type of insulator. As described in [1], experimental studies have clearly shown that there is a difference between DC and AC arc propagation across the insulator surface. Under AC voltage the dry band arc will extinguish and needs to re-ignite at each voltage zero. Furthermore, it is found that the arcs tend to propagate along the insulator surface under AC energization while DC arcs are more likely to leave the surface and propagate in the air, as is illustrated in Fig. 3.7 optimized insulator profiles, which have a larger shed, or under-rib, spacing than is the practice for AC insulators.

3.9.1 Principle of Insulator Dimensioning DC The essence of dimensioning insulators with respect to contaminated (or polluted) conditions is to select the insulator dimensions to obtain an acceptable level of flashover performance in the network. The basic principles applied in the insulation dimensioning process can be described with reference to Fig. 3.8 [1]. The variability of the environmental stress is described by a statistical frequency distribution function, f (γ). The statistical nature of the dielectric strength of the insulation may also be expressed in terms of a statistical function, P(γ). The risk that a flashover may occur is given by the area underneath the curve which is obtained by multiplying and integrating the stress and strength probability functions. The larger the area, the higher the risk of flashover. The aim of Fig. 3.7 Schematic representation of dry band arc propagation under DC and AC voltage

48

R. Stephen and J. Iglesias

Fig. 3.8 Fundamental approach to the insulator dimensioning process [1]

the dimensioning process is to optimize the risk of insulator flashover accounting for the additional cost and feasibility of increasing the insulator flashover strength. The tasks are to obtain, in this case, the function f (γ) for the pollution severity and the function P(γ) for insulator pollution performance. Function f (γ) may be estimated from regular site severity measurements over a considerable period, while function P(γ) may be obtained through some form of pollution testing, whether under natural conditions or in the laboratory. For HVDC systems, the application of a detailed statistical design approach [17] is considered beneficial in view of the importance of an optimal insulation design with respect to pollution. The main obstacle in applying the statistical method is therefore to quantify the input parameters with sufficient accuracy to warrant this approach [18]. In particular: • The statistical distribution of the pollution severity (i.e. stress) may vary along the line, or at different locations in a station; thus, not all insulators will be exposed to the same stress. • Each insulator type has its own strength characteristic, so the statistical distribution of the strength needs to be determined individually for each insulator type. • The number of pollution events (i.e. times when there is a non-zero probability for flashover) may vary from site to site and from year to year. Note that a cautious approach is recommended when defining the USCD according to [11], as the increasing data from different tests suggest that the theoretical curves may be over-pessimistic [19].

3 Insulation Coordination

49

3.9.2 Insulators for DC Lines Three types of insulators are commonly used for modern DC lines: • Ceramic insulators made from glass or glazed porcelain. These are commonly used. • Composite insulators, which consist of a fiberglass-reinforced plastic (FRP) core or tube, which provides the mechanical strength to the insulator, and a polymeric housing to seal the rod from the environment and to provide the required creepage distance and profile for the pollution performance. These are also commonly used. • Hybrid insulators which have a ceramic core (glass or porcelain) covered by a polymeric housing. This type includes the silicone coated glass or porcelain which have been extensively used in the last years. When considering the choice of insulators, it is important to consider the following performance aspects: • Prospective life and life cycle costing: The life expectancy and possible additional costs and efforts for condition assessment, replacement, and maintenance, need to be factored into the selection process. • Pollution flashover performance: Aged polymeric insulators may show some reduction in flashover performance because of increased surface roughness (thus attracting more pollution), or a reduction in hydrophobic properties. These ageing aspects need to be factored in when selecting insulation (creepage) distances. • Corrosion of the end fittings: corrosion of metallic end fittings is more prevalent on DC systems. This may result in a reduction of the mechanical strength of the insulator, or negatively impact the flashover performance if the insulating surface is coated with corrosion by-products. Long rod designs will suffer less from corrosion than cap and pin designs, because of less metal parts in the insulator string. However, to minimize the problem, particular designs for DC have been developed, like the use of large zinc collar on the caps and zinc sleeve at the pins. The use of composite insulators, in particular those with housings made of hydrophobicity transfer materials (HTM), are attractive for HVDC systems as they offer an improved flashover performance compared with ceramic or glass insulators. Documented service experience [20] shows that polymeric insulating materials have been successfully implemented for DC line insulators since the 1980s and a record of good service experience has been built up for the designer to be confident about their performance. This early survey highlighted, however, some instances of severe erosion in high-pollution areas and corrosion of the end fittings. The results should, however, be seen against the rather limited number of insulators in the sample (i.e. less than 1000 units) and their relatively short service

50

R. Stephen and J. Iglesias

(i.e. less than 10 years) at the time of the survey. Other experiences have reported good service performance [1]. It is important to note that the type of glass for cap and pin insulators intended for DC differ from the type used for AC, as well as the type of porcelain, while composite insulators for AC and DC applications generally use the same polymeric material. HTV silicone rubber, which is commonly used for composite insulators, contains the filler material ATH (Alumina-trihydrate) for improved tracking resistance. This filler material also improves the performance of the silicone rubber in HVDC applications as it reduces the housing’s tendency to accumulate and retain space charge on its surface [21]. With other silicone rubber formulations, e.g. RTV or liquid silicone rubber products, it may be necessary to consider the addition of anti-electrostatic agents to avoid the accumulation of space charge. Hydrophilic insulators, such as EPDM, on the other hand, have a lower surface resistance which is beneficial for the drainage of space charge from the surface and therefore special additives are generally not required. Unfortunately, they do not inhibit the development of the conducting layer, as is the case with hydrophobic materials and their flashover performance is therefore not as good, but they nevertheless demonstrate slightly improved performance compared to porcelain insulators in pollution tests. In contrast to ceramic insulators, where under-dimensioning usually results in an inadequate flashover performance, under-dimensioning of composite insulators may also result in premature ageing. It is therefore important to consider the longterm ageing performance of composite insulators for HVDC applications.

References 1. CIGRE Technical Brochure 518. Outdoor insulation in polluted conditions: guidelines for selection and dimensioning. Part 2 the DC case. Working Group C4.303. Paris (2012). www. e-cigre.org 2. CIGRE Green Book. Overhead Lines. Springer, Paris. ISBN 978-2-85873-284-5 (2014). www. e-cigre.org 3. CIGRE Technical Brochure 583.Guide to the conversion of existing AC lines to DC operation. Working Group B2.41. Paris (2012). www.e-cigre.org 4. CIGRE Technical Brochure 388. Impacts of HVDC lines on the economics of HVDC projects. Joint Working Group B2/B4/C1.17. Paris (2009). www.e-cigre.org 5. CIGRE Technical Brochure 63. Guide to procedures for estimating the lightning performance of transmission lines. WG 33.01. Paris (1991). www.e-cigre.org 6. IEC 71-2. Insulation Coordination. Part 2. Application Guide. Geneva (1996) 7. IEC 71-1. Insulation Coordination. Part 1 Definitions, Principles and Rules. Geneva (1993) 8. CIGRE Technical Brochure 340. Utilities Practices Toward Sustainable Development. WG C3.03. Paris (2008). www.e-cigre.org 9. CIGRE Technical Brochure 72. Guidelines for the Evaluation of the Dielectric Strength of External Insulation. WG 33.07. Paris (1992). www.e-cigre.org 10. Kiessling, F., Nolasco, J., et al.: Overhead Power Lines, 1st edn. Springer Verlag. ISBN 3-54000297-9 (2003)

3 Insulation Coordination

51

11. IEC Standard 60815-4. Selection and Dimensioning of High Voltage Insulators Intended for Use in Polluted Conditions. Part 4: insulators for DC Systems, 1st edn (2016) 12. Kawamura, T., et al.: DC Pollution Performance of Insulators. CIGRE Paper 33-10. Paris Session (1984). www.e-cigre.org 13. Cortina, R., et al.: Study of the Dielectric Strength of External Insulation of HVDC Systems and Application to Design and Testing. CIGRE Paper 33-12. Paris Session (1984). www.e-cig re.org 14. Pigini, A., et al.: Performance of Insulators for EHVDC Systems Under Polluted Conditions. CIGRE Paper 33-22. Paris Session (1988). www.e-cigre.org 15. Baker, A.C., et al.: A comparison of HVAC and HVDC contamination performance of station post insulators. IEEE Trans. Power Deliv. 4(2), 1486–1491 (1989) 16. Kimoto, I., Fujimura, T., Naito, K.: Performance of insulators for direct current transmission line under polluted condition. IEEE Trans. Power Apparatus Syst. PAS-92(3), 943–949 (1973) 17. Engelbrecht, C.S., Hartings, R., Lundquist, J.: Statistical dimensioning of insulators with respect to polluted conditions generation. In: IEE Proceedings Transmission and Distribution, vol. 151, no 3 (2004) 18. Long, Y., et al.: The reliability study of the statistical method on insulator dimensioning of (U)HVDC lines with regard to pollution conditions. In: 6th International Conference on Power T&D Technology. Guangzhou, China (2007) 19. George, J.M., et al.: Correlation assessment between actual pollution performance of insulator strings in DC and theoretical models. In: 13th INSUCON Conference. Birmingham, UK (2017) 20. Electra No. 161. Service performance of composite insulators used on HVDC lines. CIGRE Working Group 22.03 (1995). www.e-cigre.org 21. Kumara, S., Serdyuk, Y., Gubanski, S.M.: Surface charge decay on polymeric materials under different neutralization modes in air. In: IEEE Transactions on Dielectrics and Electrical Insulation, vol. 18, no 5 (2011)

4

Phase/Pole Configuration, Conductor and Hardware

Contents 4.1 4.2 4.3

Phase Configurations (AC) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 54 Pole Configurations (DC) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 55 Conductor Selection . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 57 4.3.1 General Procedure to Optimize the Selection of Conductors . . . . . . . . . . . . . . . . 57 4.3.2 Economic Analysis . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 59 4.3.3 Additional Investigations . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 64 4.3.4 Conductor Selection Example . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 66 4.3.5 Mechanical Determination Based on Different Surfaces . . . . . . . . . . . . . . . . . . . . 68 4.3.6 Conductor Based Electrical Characteristics . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 71 4.3.7 Groundwire Selection . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 75 4.4 Hardware Designs . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 76 4.4.1 Electrical Aspects . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 77 4.4.2 Mechanical Aspects . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 78 4.5 Tower Designs . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 88 4.5.1 Tower Design Considerations . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 88 4.5.2 Tower Design Options . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 92 4.5.3 Other Considerations for Tower Compaction . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 93 4.6 Anti-galloping Considerations . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 94 References . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 100

Abstract

This section describes the different phase or pole configurations that can be used for compact lines. They need to be divided into Right of Way (ROW) reduction and Surge impedance Loading (SIL) improvement (only for AC lines). For ROW reduction examples such as vertical configuration, compact delta with composite post cross arms, etc., can be described. For SIL improvement, increased bundle diameter, asymmetrical shaped bundles in delta or inverse delta with composite cross arms are proposed for study. The DC overhead power lines do not improve the power flow by modifying pole spacing or the bundle diameters, unlike in AC overhead power lines, where these parameters affect the

© Springer Nature Switzerland AG 2024 R. Stephen and J. Iglesias (eds.), Compact Overhead Line Design, Compact Studies, https://doi.org/10.1007/978-3-031-44524-8_4

53

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R. Stephen and J. Iglesias

surge impedance loading of the line. Therefore, in DC compact lines, the different pole configurations pursue a reduction of the Right of Way, a reduction of the visual impact and/or an optimisation of the corona-related effects (electric field, ion current, audible noise, etc.). The limits to these effects may often be the governing aspects of the design of compact DC lines. The overall design of a compact line in general considers this configuration as a primary concern, which is complemented with the conductor selection process, tower and foundation designs and hardware solutions. All these aspects are included in this section, which also gathers a general discussion on galloping, as it may be one of the major issues in compact lines due to the reduced clearances between phases or pole conductors and/or between them and the groundwires.

4.1

Phase Configurations (AC)

Phase configuration, as mentioned in [1], will have a strong influence on EMF values at ground level. In fact, if we convert the values there presented into p.u., considering 1 the highest value, the magnetic field can be reduced by 43% just by changing the configuration from horizontal to triangle (Table 4.1). Also from [1], as previously mentioned, the OHL parameters can be joined into two major groups: those that influence the EMF value at ground level, and those that influence the EF on the conductor surface and hence the corona effect. In the first group are “phase to phase distance”, “conductor height above ground” and, to a less extent, the “number of sub-conductors”. In the second group the main parameter to consider is the “number of sub-conductors” and the “phase to phase distance”. See Table 4.2.

Table 4.1 Influence of phase configuration on EF, MF, RI and AN [1] Configuration

Electric field (p.u.)

Magnetic field (p.u.)

Radio inteference (p.u.)

Audible noise (p.u.)

1.00

1.00

1.00

0.98

Single circuit OHL Horizontal Delta

0.85

0.80

0.94

1.00

Vertical

0.97

0.63

0.91

0.96

Triangule

0.85

0.57

0.94

1.00

Double circuit OHL Vertical

1.00

0.75

0.94

0.97

Low impedance

0.91

0.83

0.94

0.99

Danube

0.91

1.00

1.00

1.00

4 Phase/Pole Configuration, Conductor and Hardware

55

Table 4.2 Influence of parameters on EF, MF, RI and AN [1] EF

Parameter

MF

RI

AN

Phase to phase distance Conductor height above ground Number of sub-conductors (for a given total cross-section) Sub-conductor spacing Total conductor cross-section

4.2

Strong increase

Strong decrease

Slight increase

Slight decrease

No significant effect

Pole Configurations (DC)

The most common scheme used for compact DC lines is the bipole, for which two main configurations are considered: horizontal, that prioritizes in general the visual impact aspects due to the lower height; and vertical, that gives more importance to the occupation and Right of Way (ROW) reduction due to the lower width. In both cases, the corona-related effects must be studied in detail to address the regulated limits, for which the pole spacing, or bundle configurations are important. For the case of two bipoles in the same line, the different alternatives of positive–negative pole position have to be evaluated in order to determine the electrical effects. Advantages in terms of reducing certain phenomena could be obtained in configurations with opposite polarities on the two sides of the tower (i.e. ± on one side and −/+ on another side, which would reduce the ground level electric field, for example). However, this may have disadvantages for other parameters (e.g. audible noise produced by positive pole is higher). The decision for an optimum configuration in each case should consider all the aspects, including the performance when only one bipole is in operation, maintenance issues, etc. (Fig. 4.1). Chapter 8 details with examples the influence of the pole configuration and bundle arrangement on the conductor surface gradient, the audible noise, the corona effect, the electric field, the ion current level, etc. In particular, for the most common horizontal configuration, a detailed sensitivity study is included. In summary, there are some parameters that reduce the surface gradient (and consequently the audible noise and radio interference): the

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R. Stephen and J. Iglesias

Fig. 4.1 Possible pole arrangements, simple configurations

increase in pole to pole distance, the increase in number of subconductors and the increase in total conductor cross section. Also, the parameters that reduce the electric field at ground level are the increase in conductor height, and the decrease in pole to pole distance. Vertical configurations can take advantage of a narrower occupation. Therefore, all the effects (electric field, ion current, audible noise, etc.) at certain distance from the axis of the line are lower than those produced by horizontal lines (keeping the other parameters unchanged), because the distance to the conductors is longer. (Fig. 4.2). Other configurations can be studied. In particular, geometrically asymmetrical solutions could be very useful in compact designs. These configurations can take advantage of the differences between positive and negative poles regarding the

Fig. 4.2 Typical configurations for bipole scheme

4 Phase/Pole Configuration, Conductor and Hardware

57

corona and field effects (audible noise generated, electric field and ion current density at ground level, lightning attraction or pollution withstand properties…). Also, as discussed previously, assigning unequal voltages to the poles or underbuilding groundwires could be studied to optimize the effects at ground level.

4.3

Conductor Selection

4.3.1 General Procedure to Optimize the Selection of Conductors The selection of the optimal conductor configuration must consider the overall system, since there are more factors relating to the choice than those that are affected by the shape and the configuration of the conductors. This has been done according to [2]. The process of this selection can be divided into 10 steps of which, the first 4 steps relate to the line life cycle costing point of view. Then, in the following steps, a few options are selected for more detailed system analyses. These steps can be explained as follows: Step 1: For every conductor configuration that meets the above planning requirements, the field effect (EMF) and corona limits (radio interference and audible noise) are to be identified. Hereby, the intended use of overhead power line carriers and the effect of the line design, especially transposition towers, need to be considered. Step 2: Based on the line loading, corona and field effect limits a combination of options of suitable conductor bundle types are to be selected. Thereafter the capital investment cost (CIC) for each option is to be estimated. The capital cost estimates must consider changes which can occur after the line profiles and soil conditions are obtained in the detail design phase. Step 3: The electrical line parameters (resistance (R), reactance (X) and susceptance (B)) are to be calculated for each option in both actual and per unit (p.u.) values. Step 4: Based on the line loading forecast, the total cost of line losses (TCO) needs to be calculated for each option for the entire lifecycle of the line. Thereafter a line life cycle costing analysis (LCC) for the different options (i.e., LCC = CIC + TCO) is to be performed. The line life cycle cost of a transmission line consists of the initial capital investment plus the cost of line losses over the life cycle of the line. It is necessary to calculate over the life of the line, the present value of the line losses, using the net discount rate prescribed by the utility’s financial guidelines. From a line life cycle costing point of view, the most economic conductor configuration will be that which gives the minimum cost in the following equation: Capex +

25 ∑ n=1

(1 + d) − n · x[cost of line losses in year n]

(4.1)

58

R. Stephen and J. Iglesias

where d n

net discount rate. year under consideration until the end of the economic life of the line (say, 25 years).

Step 5: Three to five most suitable conductor options are to be selected for detailed system analysis studies. For long overhead power lines (> 150 km) or shorter but highly loaded lines, unbalance studies are to be performed to determine the need for phase transposition or phase optimization for parallel lines. Step 6: The new overhead power line will be part of an interconnected transmission system. Hence, it is also essential to consider the losses from an overall system point of view. Thus, to make a better decision regarding conductor selection, detailed system analysis studies should be performed in order to calculate the cost of system losses for each option for the entire life cycle of the line. It is necessary to calculate over the life of the line, the present value of the savings in system losses (minus value), using the net discount rate prescribed. Step 7: For short lines, the thermal limits need to be considered. Thermal capacity will be directly proportional to the size of the conductor, or cross-sectional area (mm2 ). Depending on operational conditions, thermal limits can be decisive in the selection of a conductor. For example, if operation in emergency conditions requires a power transfer significantly above the normal operation, then the selection of the configuration will be dictated by thermal limits rather than by the economical loading. Permanent operation close to or at thermal limits will always be significantly above economical loading, because of very high losses amounting, in total, to much more than the cost of construction. Step 8: One of the main purposes of the new line is to extend the power transfer margin. The power transfer margin is dependent on the voltage collapse limits, which are related to the surge impedance of the line. Surge impedance loading (SIL) is a measure of the power that can be transferred without reactive compensation. SIL depends on the conductor bundle and line configuration. Different sizes of conductor and bundle will give different SIL and the price that must be paid for a possible increase of SIL must be evaluated. There is a cost benefit for having a higher voltage collapse or power transfer margin, as this will allow more load to be added on to the network without the need for further reinforcement. This implies that options with a larger margin will be beneficial. It is difficult to place an exact monetary value on this benefit, but for the purposes of this discussion, the cost of adding shunt capacitor banks to make up for the lost power transfer margin can be calculated to compare the different cases. Thus, the benefits of higher surge impedance loading need to be verified by performing voltage analysis or voltage collapse studies. This will allow for the benefits of a higher surge impedance loading to be quantified, which is relevant for long overhead power lines which are voltage rather than thermally constrained.

4 Phase/Pole Configuration, Conductor and Hardware

59

Step 9: The operating and maintenance costs and the need for live-line maintenance for each conductor configuration is to be considered. Step 10: The need for high reliability and the differences in reliability for each option must be considered. After getting close to the general selection of the conductor configuration deeper studies can be done considering the mechanical and the electrical determination of the overhead power lines. This will be done by investigating the factors that relate to the conductor choice and compare them for different surfaces, trapezoidal and round, and the number and diameter of sub-conductors in a bundle. For the evaluation of several design options (tower, foundation, conductor, and phase configuration), the Appropriate Technology Index (ATI) as described in [3] should be used. The configuration and arrangement of the DC poles are a key aspect of compaction. The overall design of a compact line in general considers it as a primary concern which is complemented with the conductor selection, tower and foundation designs and hardware solutions. This chapter revises all these aspects and their relationship with the distance’s reduction or compaction. Also, this chapter includes a general discussion on galloping, as it may be one of the major issues in compact lines due to the reduced clearances between pole conductors and/or between pole conductors and groundwires.

4.3.2 Economic Analysis The conductor selection, as previously described, is carried out based on economics, the basis being the minimization of the line cost and its losses. However, prior to economic evaluation, general studies are carried out to ascertain conductor bundle’s suitability regarding electric field, surface gradient, RI, AN etc. Based on the selected conductor bundle configuration, preliminary tower geometry is developed, and insulator, hardware and accessories are decided. For the preliminary conductor selection, some equations are used for the line costs. They are functions of their type, size, number of conductors in the bundle, and line voltage. The losses cost is a function of the power to be transmitted, its peak value, yearly power duration curve, voltage, and the cost of the energy. Depending on the purpose of the line, the load duration curve cannot be well defined due to the new generation installed in the system, their characteristics, and the power sharing in various parallel lines. It is more precise when the line is dedicated to a strong generation (e.g. a distant hydropower plant) or a HVDC system where the power is limited by the converter rating. After this preliminary selection, the range where the economical conductor is located is known and some specific alternatives are established to carry out a dedicated economical evaluation.

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R. Stephen and J. Iglesias

Transmission Line Cost As described, a regression equation is established for line cost per km (C L ). In this case, this cost will be set as a function of the voltage (V ) and conductive section of the aluminum (S) of one of the AC phases, or the DC poles, if it is the case. C L = f (V , S)

(4.2)

According to [4, 5], the investment cost per km of a transmission line can be estimated by the following equation. C L I = a + bV + S(cN + d)

(4.3)

where V S N

Line voltage (phase-to-phase for AC, pole to ground for DC) in kV Total aluminum cross section of one phase, or pole in MCM (thousands of circular mils) Number of conductors in a bundle configuration.

Note: 1 mm2 = 0.507 MCM. In [4, 5], the values of a, b, c and d were obtained through regression analysis based on the cost values of ten AC and ten DC configurations. For these configurations, a detailed design of the line (both electrical and mechanical analyses) was carried out, thus, obtaining their proper cost. The weight of the towers, Right of Way width, insulator and hardware, their corresponding costs, etc. were evaluated. Indeed, these costs are dependent on local conditions like government taxes, labor costs, design criteria, and engineering and administration costs. If desired, the a, b, c and d parameters can be re-defined having in hand local line costs and their configurations from a database. The mentioned parameters, for ACSR (Aluminum Conductor Steel Reinforced) conductors are shown in Table 4.3 which are related to Brazilian conditions. Once the values for N and V are set, the line investment per km (C L I ) and the yearly cost (C L I y ) become:

Table 4.3 Transmission line cost constants (cost in US$ per km)

CL I = A + B S

(4.4)

CL I y = f y A + f y B S

(4.5)

AC line

DC bipole

a

78,252

86,360

b

264.24

130.3

c

1.390

1.586

d

34.3

25.9

4 Phase/Pole Configuration, Conductor and Hardware

61

Cost of Joule Losses Per Unit Length The line Joule losses per km, for a certain power, P, pole resistance and unit length, are calculated through the following equations: For AC lines: L AC = 3

ρ 2 I NS

P I =√ 3V

(4.6) (4.7)

For DC lines: L DC = 2 I =

ρ 2 I NS

P 2V

(4.8) (4.9)

They are functions of the transmitted power (P), the line voltage (V), the conductor resistivity (ρ) and the number of conductors in the bundle (N). Note that for aluminum conductors the conductor resistivity is 57 Ω/MCM/km. The transmitted power is not constant in time; therefore, to get the yearly losses it is necessary to define the loss factor (l f ) which is the number of hours along the year that transmitting the maximum load gives the same losses as the variable dispatch (see Fig. 4.3). In this figure, the average power can be calculated by using the power duration curve and the load factor can be calculated as well (average value divided by the peak power). Fig. 4.3 Load duration curve

62

R. Stephen and J. Iglesias

The cost of the Joule losses per km is therefore: ( ) C L J = C1 + C2 l f 8760 L p

(4.10)

where C1 C2 8760 Lp

Fixed cost of generation (US$/MW) Energy cost (US$/MWh) Number of hours in a year Losses (AC or DC) at peak transmission.

In summary, the Joule losses for a certain P (peak) and V can be expressed as: CL =

C S

(4.11)

Note: Corona losses should also be included in the economical evaluation; however, they are smaller compared to the Joule losses and may be neglected at least in the preliminary evaluation. Line and Joule Losses Cost The yearly cost of the line investment plus the Joule losses (C L L ) will be: ( CL L =

L

f y A + f yBS +

) C L S

(4.12)

being the line length. This function reaches its minimum value at: √ S = Secon =

C f yB

(4.13)

By varying the number of the conductors in the bundle (N), the best line cross section can be obtained. Note that Secon does not depend on the line length. Specific calculations can be carried out for different values of N. Note: Normally ampacity is not an issue for DC line as the current, in general, is limited by the capacity of the converter stations. System Costs In order to set certain characteristics of the system (e.g. rated voltage, conductor configuration etc.), an economical evaluation may be conducted. This evaluation should consider:

4 Phase/Pole Configuration, Conductor and Hardware

63

• Investment costs – Transformer costs – Line costs – Substation costs – Shunt (reactor) and series (capacitor) compensation in the lines. • Operational costs – Energy losses – Maintenance, etc. These investment costs (C I ) are a function of the voltage (V ) and power/current (P). C I = f (V , P)

(4.14)

The investment cost can be decomposed in: • line cost (C I L ) and • substation/equipment cost (C I S ). CI = CI L + CI S

(4.15)

The cost for joule losses (C J ) is a function of the line/equipment conductor resistance, current, and energy costs. This can also be split into line losses cost (C J L ) and equipment losses cost (C J S ). Thus, CJ = CJ L + CJ S

(4.16)

Losses are calculated on a yearly basis; therefore, in order to add to the investment cost one should: • Capitalize the losses in a period of n years, or, • Evaluate the yearly cost of the investments (amortization in a period of n years). In this analysis, it was chosen to evaluate the yearly cost of the investment. If an investment must be recovered in a period of n years at a return rate j, then, the yearly component is the investment multiplied by a constant (k), being: k=

j 1 − (1 + j)−n

(4.17)

Usually, the yearly maintenance cost is also included (both live line and normal), and it is defined as a fraction of the investment per year (say, 2%). Therefore, the yearly cost of an investment results in: C I y = (0.02 + k)C I = f y C I

(4.18)

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R. Stephen and J. Iglesias

To estimate the investment cost, the historical cost database of the utility can be accessed, or, alternatively, information from some manufactures or utilities can be collected. In general, these costs are represented in the form of equations as a function of V and P, obtained through regression analyses of the information available. The AC system cost (C SY S ) is: C SY S = C I S + C I L + C J S + C J L

(4.19)

Each of these components have been defined previously. All components are voltage dependent, some of them increasing or decreasing with it. Therefore, there will be a voltage that minimizes the system cost. It should be noted that the parameters C I L and C J L vary with the line conductor cross section, whereas the other parameters do not. Hence, it should be first defined before minimizing the overall equation. This pre-optimization process is carried out considering C I L and C J L , as the rest of the variables are not influenced by it (see details in the next section). For a DC system, two additional terms must be included: the converter station cost (CC S ) and the converter station losses (C J C S ). Indeed, the line equation and losses must be properly changed [4].

4.3.3 Additional Investigations Corona Losses Once the pole conductor cross section is determined, the cost of corona losses can be included searching for another configuration. Corona losses are proportional to the conductor surface gradient, bundle configuration, tower top geometry, and weather. As suggested in [4], the inclusion of corona losses will lead to a little higher conductor cross section. Type of Conductor and Mechanical Design (Stringing) Instead of ACSR (Aluminum Conductor Steel Reinforced) one may search for other types of conventional conductors, for instance: • • • •

AAC (All Aluminum Conductor); AAAC (All Aluminum Alloy Conductor); ACAR (Aluminum Conductor Alloy Reinforced); AACSR (Aluminum Alloy Conductor Steel Reinforced).

In this case the cost equation shall be revised or the calculation for a selected cases around the ACSR economical section shall be carried out. Note that for the same conductive area, resistances and diameters may differ. Different conductor types have different unit weights and breaking loads, the latter influencing the EDS (Every Day Stress), stringing condition, the tower

4 Phase/Pole Configuration, Conductor and Hardware

65

height, and applied forces; therefore affecting the tower and foundation related cost. Also, other non-conventional conductors may be considered in the process of conductor selection, like the so-called High Temperature Low Sag (HTLS) conductors. This includes several types (see [6, 7]). Note that the sag variation with the conductor temperature is quite different depending on the type of conductor used, so the conductor performance can be optimized depending on the transmission overload capacity. These type of conductors are generally used in case of high current carrying capacity requirements (typically up to 1.5–2 times the current carrying capacity of conventional conductors) and similar sag requirements. It is important to highlight that for HVDC lines the power flow can be generally controlled in the converter stations, for it may be usual to set this power flow close to the maximum capacity of the line continuously. As, in general, HVDC are pointto-point transmission, the capacity of the lines is the same as of the converters. The situation is different considering the system as multiterminal (expandable) or a DC grid. To get a compromise of losses cost and current capability, it must be highlighted that conventional conductors lead to maximum temperatures in the range of 60–90 °C, while HTLS conductors become important when temperatures above 150 °C are needed. Operation at high temperatures over long periods of time may lead to very high line losses, as the conductor resistance is very temperature dependent, so this must be considered. Note: designs to optimize some aspects of the lines, like wind induced motion or corona noise, may be considered, making the overall design vary and making the limits be reconsidered. Sensitivity to Parameters Adopted Many parameters impact the result: unit cost of losses; line material; currency, rating… The calculation above described was based on the life cycle cost, but it may occur to be important for the investment cost alone (difficulties of loan, money etc.), and other requirements like, environment considerations. There are always uncertainties in the future utilization of the line and a more expensive solution may be a better choice provided for bigger current capacity as an example. Reference [2] analyzes uncertainties in another problem: system configuration including definition of system voltage. Alternative configurations are set, costs are evaluated, and probable scenarios are evaluated. For every configuration a score is assigned connected with the scenario. The scores are weighted by the scenarios probability to define a composite score to orient the decision. In an example the life cycle cost; capital investment cost; MVA thermal; and conductor surface gradient; were considered for various voltages; bundle numbers; and the ACSR conductor.

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R. Stephen and J. Iglesias

4.3.4 Conductor Selection Example Optimization Based on Life Cycle Cost With the methodology explained above, based on life cycle cost of the line, the pole conductor configuration was calculated for a bipole ± 500 kV; 1300 MW (peak load) with 3 ACSR conductor per pole. As a result, the 1590 MCM, code Lapwing, was selected as initial value. Consider, therefore, a base case: three ACSR 1590 MCM (806 mm2 ) as initial selection. Other alternatives are considered as shown in Table 4.4. The following comments apply to this Table 4.4: • • • • • • • • • •

NA: not evaluated. N = conductors per pole; Rdc = DC resistance; w = weight; RBS = Rated breaking strength; H/w = parameter (tension over weight ratio); CL + CLL = line costs + losses cost. For cases 1 and 2: the Case 2 has bigger life cycle cost; smaller corona losses, does not meet H/w criteria for aeolian vibration [8], sag is smaller, conductor surface gradient (Gc) is smaller, wind force on conductor and tower is bigger. From case 2 and 3: Case 3 meets H/w criteria (terrain category 4: trees and buildings etc.) but leads to a bigger sag. Case 4 and 1: Case 4 has higher sag, lower H/w, lower Gc. Case 4 and 5: Case 5 has an increase in H/w which brings a sag similar to case 1. Case 1, 6, 7 and 8: Impact of conductor type: diameter/forces, H/w, sag, Gc and corona losses. Case 9: same as base case but with a larger conductor. Category 4* means H/w = 425 m.

Therefore, to be able to compare the configurations the tower and foundation calculations and specific cost determinations for each case are necessary. Multi Criteria Decision As mentioned before, other scenarios may be considered than life cycle cost. An example is found in [2] item 8.2. There, the decision is oriented by a procedure mainly based in “qualitative scores”. A similar approach will be done here with slightly different procedure, considering the cases 1, 2, 7 and 9. The criteria of orientation decision are: • • • •

LCC —Life cycle cost (line investment plus capitalized Joule losses cost). LINV —Line Investment AMP—Current carrying capability (for future use). ENV—Environment (based on tower height).

1192.5 (604)

4

4

3

3

3

3

3

3

2

3

4

5

6

7

8

9

1780 (902)

1590 (805.6)

1700 (811)

1973 (999.7)

1590 (806)

1590 (806)

1192.5 (604)

1590 (806)

3

1 Base

MCM (mm2 )

N

Case

ACSR

AACSR

ACAR

AAAC

AAC

AAC

ACSR

ACSR

ACSR

Type

40.7

38.22

38.16

41.14

36.90

36.90

33.97

33.97

38.22

Diam; mm

0.0107

0.0139

0.0119

0.0110

0.0119

0.0119

0.0120

0.0120

0.0119

Rdc pole; Ω/km

3.089

2.671

2.375

2.766

2.221

2.221

2.280

2.280

2.671

w; kg/m

227.7

308.2

180.0

281.9

119.6

119.6

186.9

186.9

187.4

RBS; kN

Table 4.4 Cases considered for conductor selection of a ± 500 kV line H/w m

988

41.0 (18)

40.1 (13)

34.2 (19)

1353

1530

1467

39.40 (14) 1499

28.00 (23) 1285

21.53 (18)

31.77 (17) 1420

33.64 (18) 1504

33.73 (18) 1287

EDS; kN (%RBS)

14.8

13.1

13.6

13.4

15.6

20.3

14.1

13.3

15.6

Sag; m

2706

2416

2433

2999

2418

2418

2416

2416

2418

Bundle area mm2

22.2

23.3

23.3

22.0

24.0

24.0

21.5

21.5

23.3

Econduct ; kV/cm

6.7

7.1

7.1

6.6

7.5

7.5

6.1

6.1

7.1

Corona; W/km

36,358

NA

NA

NA

NA

NA

37,058

37,058

36,279

CL + CLL ; $

4 Phase/Pole Configuration, Conductor and Hardware 67

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R. Stephen and J. Iglesias

Here, for the alternatives analysed, the values were evaluated following [4] and are shown in Table 4.5. Comment: LCC and LINV cost of alternative 7 was estimated by comparison with alternative 1. Both have similar diameter (therefore similar effect of wind in the line); they have different conductor weight; the impact estimated is in tower weight 2% (case 7 lower than case 1); and difference in sag and tower height leads to alternative 7 tower weight being 4% lower; tower/foundation participation in the line cost is 26% [4]. As a result, the cost of the line in alternative 7 would be 1.5% less expensive. ACAR conductor is 4.7% more expensive and conductor participates with 37% in the line cost resulting therefore that alternative 7 would cost 1.8% more than alternative 1. As a result of the combination of the effects it can be estimated that Alternative 7 would cost say ~ 0.5% more than alternative 1. Note: If the same methodology is applied to HTLS conductor (HTLS not included in [8]) the sag would be 14 m (a bit lower than for the base case) and the cost of conductor is estimated as 3–4 times bigger, therefore is more expensive than the alternative 1. The values of Table 4.5 were used to evaluate the “Decision Orientation Index” in Table 4.6. LCC includes the cost of line (LINV ), and the use of both may look like a duplication of one effect, but LINV must be seeing not due to value but as a difficulty in getting the loan participation of local industry and services; and will be considered as of small importance. AMPAC is considered assuming that in the future others converter can be connected in a HVDC multi terminal configuration. ENVIR is based on tower height visual impact. Losses are almost the same for all conductors’ configurations. In conclusion alternative 1 is the best, followed by alternative 7.

4.3.5 Mechanical Determination Based on Different Surfaces The overhead power lines are exposed to ambient conditions such as wind and ice loading. However, the conductor system needs to be designed to minimize the effect of wind and ice loadings. This is generally achieved by using fewer conductors in the bundle to minimize the wind load. In addition, the lower the steel content the lower the ultimate tensile strength (UTS) of the conductors and hence lower loads result in the strain towers allowing for lighter tower designs. The same applies to ice loading with fewer conductors in the phase bundle the lower the overall ice load. Factors Relating to Conductor Choice The mechanical determination of the overhead power lines is influenced by the load on the conductor which in turn is influenced by several other factors. These include the wind speed which is influenced by the roughness factor for different terrain

1590 (806)

1780 (902)

1700 (861)

3

4

3

3

Base 1

2

9

7

1192.5 (604)

MCM (mm2 )

N

Altern

ACAR

ACSR

ACSR

ACSR

Type

Table 4.5 Values to compare alternatives

36,412

36,358

37,058

36,278

LCC ($)

100.3

100.2

102.2

100.0

LCC (%)

26,953

27,907

27,597

26,818

LINV ($)

100.5

104.1

102.9

100.0

LINV (%)

3675

4050

4000

3675

AMP (A)

100.0

110.2

108.8

100.0

AMP (%)

45.5

46.6

45.1

47.4

ENV-height (m)

96.0

98.3

95.1

100.0

ENV-height (%)

4 Phase/Pole Configuration, Conductor and Hardware 69

70 Table 4.6 Values to compare alternatives

R. Stephen and J. Iglesias

Altern.

p.u.

%

1

0.348

34.8

2

0.193

19.3

9

0.227

22.7

7

0.232

23.2

categories, the conductor diameter and some other factors that are further explained in this section. Wind Loads The load on the tower, due to wind, is a function of the load on the conductor, which in turn, is a function of the conductor diameter. If the cross-sectional area is increased (thus increasing the diameter when using the same fill factor) in comparison to the previous conductors, there could be a need to strengthen the towers. This is often not possible due to environmental constraints or could be prohibitively expensive. The reason for such gain of trapezoidal conductors in the wind-excited response is, above all, due to its aerodynamics. As the wind velocity reaches the range of 30–40 m/s, the drag coefficient of the classical conductor, being post critical, does not vary too much. As result, the drag force is free to fluctuate. Simultaneously, C xc of the trapezoidal conductor fluctuates inversely proportionally to the wind fluctuations, making the drag force quasi-constant at V between 30 and 40 m/s. Thanks to such stagnation of the drag force in that velocity region, beyond the critical state the trapezoidal conductor is still much less loaded as compared to the stranded conductor (Fig. 4.4).

Fig. 4.4 Variation of drag force per unit length versus wind velocity for classical stranded and trapezoidal conductors [9]

4 Phase/Pole Configuration, Conductor and Hardware

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Regarding this graphic, it can be said that using trapezoidal conductors at wind velocities beneath 30 m/s is not of an advantage from the point of view of the load affecting the conductor, but at greater wind velocities it can be. The case study is further described in the Chap. 8. Ice Loads There are two main types of icing: precipitation icing and in-cloud icing [10]. In mountains or regions where both types of icing may occur, the different data for the two types may be treated separately, with separate distributions to provide the basis for the design load. Ice load should ideally be deduced from measurements taken from conductors and locations representative of the line. These measurement techniques are described in [11]. A very important factor with ice accretion is the effect of the terrain. It is difficult to transfer knowledge acquired from one site to another because the terrain strongly influences the icing mechanism. For design purposes, icing data from measuring stations near or identical to the line site are ideally required. Very often, this will not be the case and service experience with existing installations will provide additional input. Yearly maximum ice loads can be evaluated by means of meteorological data analysis or an existing accretion model can be used, if available, to use for statistical approach. Ice Load Combined with Wind Load The action of wind on ice-covered conductors involves at least three variables: wind speed that occurs in presence with icing, ice weight and ice shape (effect of drag coefficient). This action results in both transversal and vertical loads. Ideally, statistics of wind speed during ice presence on conductors should be used to generate the combined loadings of ice and wind corresponding to the selected reliability level.

4.3.6 Conductor Based Electrical Characteristics Effect of Different Surfaces Trapezoidal shaped strands achieve a higher fill factor (as shown in Fig. 4.5) and are more efficient in current transmission compared to traditional round strands. Existing methods for surface gradient calculations ignored the shape of the strands. To obtain more information on surface gradients for different shapes of strands, a novel method was developed. From the electric field plot along the surface of the conductor, the following conclusions can be obtained:

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Fig. 4.5 Trapezoidal strands (left) and round strands (right) [12]

• The round stranded conductor has a higher maximum surface gradient compared to a trapezoidal stranded conductor. • The maximum electric field for a trapezoidal shaped strand is located at the corners while the maximum electric field for a round shape strand is located at the tip of the circle furthest from the conductor centre. • On the circumference of a conductor fabricated with trapezoidal strands, there are large continuous lengths with approximately same surface voltage gradient. • On the surface of the round strands, the surface gradient varies along the strand surface and there is no continuous area with same voltage gradient (Fig. 4.6). In the Fig. 4.7 the arc length along the edge of conductor strands is chosen to represent the surface distribution of electric field. The horizontal axis refers to the electric field strength and the vertical axis represents the integrated arc length which has a surface gradient value above a certain level. If 16 kV/cm is selected as a typical level to examine the field distribution, the trapezoidal stranded conductor has approximately 88 mm circumference above this level while the round stranded conductor has about 59 mm circumference above 16 kV/cm. If a higher level of electric field is selected as the threshold, take 20 kV/ cm as an example, the round stranded conductor has a larger area above this value than the trapezoidal stranded one. Figure 4.7 describes the circumferential length above a threshold value of voltage gradient. The next step is to decide the threshold value which must be considered. A hemispherical protrusion is introduced to the existing model to compute the enhancement of electric field. As presented in Figs. 4.8 and 4.9 when a protrusion is applied to the surface of the conductor, the local electric field is increased due to the relatively large curvature created by the protrusion. This field enhancement is not only determined by the shape and size of the protrusion but also depends on the location of it. Hemisphere protrusion with a range of the size (radius: 10, 50, 100 and 200 µm) is applied on both trapezoidal strands and round strands. Finite element method is employed to evaluate the electric field enhancement. By varying the location where the protrusion sits, the relationship between surface Hemisphere gradient with protrusion and without protrusion is established in Figs. 4.8 and 4.9. From Figs. 4.8 and 4.9, if the worst scenario is taken into consideration, the threshold value for surface gradient without protrusion is marked in dashed line

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Fig. 4.6 Trapezoidal strands (GAP) and round strands (AAAC) comparison [12]

(14.7 kV/cm for trapezoidal strands and 15.3 kV/cm for round strands). Referring to Fig. 4.7, the correlated surface arc length for trapezoidal shape strands is approximately 88 mm while the correlated surface arc length for round shape strands is approximately 62 mm. For these arc lengths smooth trapezoidal strands may improve corona performance compared to round wire designs of the same diameter due to their smaller surface gradients. However, these results also depend on the applied voltage. If the voltage goes higher, the surface gradient of the strands will be higher as well.

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Fig. 4.7 Arc length with surface gradient above a certain level

Fig. 4.8 Surface gradient enhancement by protrusion for trapezoidal stranded conductor [12]

Furthermore, sufficient conductor diameter/surface area can provide the appropriate level of mitigation of corona. By increasing the conductor diameter, the surface gradient can be decreased which results in a decreased corona discharge. The bundling of conductors assists in the effective increase in overall conductor diameter. Only using a large diameter conductor instead of a conductor bundle

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Fig. 4.9 Surface gradient enhancement by protrusion for round stranded conductor [12]

would result in other electrical disadvantages, such as the increased potential to create audible noise. Conductor selection may have different phases when some specific optimizations are carried out. One can start looking at the economic aspects and find the conductive material area with one type of conductor and then carry out investigations with alternatives close to the value and analysing uncertainty.

4.3.7 Groundwire Selection Groundwires are installed in the lines to avoid lightning striking the conductor. The probability of direct flashover is then reduced improving lightning performance of the line. Depending on the tower top geometry and location, the use of groundwire may be different. In places with low lightning activity, only one groundwire usually gives good protection. However, in most cases two groundwires are used. They are in general steel made, extra high strength, and diameter 9.5 mm is sufficient at least in areas without ice. The groundwire is selected based on short-circuit rating and surface gradient. The surface gradient on groundwires can be calculated based on theory of images using capacitance matrix and potential matrix. When short circuits in the substation are of high magnitude in the lines close to substation (1–2 km) steel wires may be replaced by ACSR or other Aluminum conductors selected based on loss of strength (annealing).

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At present, communication is a main consideration and the groundwires are being substituted by OPGW (optical groundwires), where the requirements are related to the messenger core (in general aluminum). They are especially important for DC lines to take care of data communication between converter stations.

4.4

Hardware Designs

This section describes the hardware required for Right of Way (ROW) reduction as well as SIL improvement (for AC lines). The hardware designs must include the use of corona rings and arching horns where applicable. It also must cover specialised hardware for use by live line maintenance staff, as it may be one of the main design aspects of compact lines. Once the phase or pole conductor configuration in view of ROW reduction and insulation coordination has been chosen, tower top geometry, insulator sets, and related hardware have to be designed accordingly. Arrangement of subconductors within phase conductor bundles will have to be considered in design of support hardware. The suspension string has a key influence on tower and line dimensions. The line can be made compact if the freedom of movement of the string and conductor is restricted. A conventional I- or double I-string can move nearly free under the influence of wind (Fig. 4.10). Cause of the movement the phase to ground (ore pole to ground) clearance in horizontal and vertical direction will be reduced. To reduce the ROW (and compact

Fig. 4.10 110 kV Double I-string. Horizontal movement

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the line) a common option is to fix the position of the conductor and string at the suspension tower. This is discussed in the chapter.

4.4.1 Electrical Aspects Electrical aspects that need to be considered in addition to insulation coordination are Radio Interference Voltage (RIV), corona and audible noise, in connection with support hardware that may necessitate fittings for grading the electric field. Protection against power arcs is another aspect that may require specific fittings like arcing horns or similar arrangements. Electrical Aspects for AC Lines In AC overhead power lines, the surge impedance loading (SIL) of the line can determine the power capacity to be transmitted. Therefore, compact designs, that reduce the phase distances and modifies the bundle configuration to improve the SIL of the line (and thus the power flow) may need specific hardware and fittings. Arrangement of phase conductors and sub-conductors within phase conductors determine the SIL. Tower top geometry, insulator sets, and related hardware must be designed accordingly. The SIL of a compact line can be increased by [13]: • • • • •

Reducing phase spacing Increasing number of subconductors per phase bundle Increasing conductor diameter Increasing bundle radius Introducing bundle expansion along the span but keeping the bundle spacing near the tower • The reduction of the space between the phases correlates direct to compact lines and low ROW. A good example of the SIL optimization is the expanded bundle design used in Brazil [14]. It requires special hardware sets, as well as studies for conductor damping (Fig. 4.11). Electrical Aspects for DC Lines In DC overhead power lines, the power flow is not increased by reducing the pole to pole spacing or by increasing the bundle radius. However, the corona and field effects may be optimized both inside the ROW and at the edge of ROW, which in some cases are limiting factors.

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Fig. 4.11 Implementation of asymmetrical expanded bundle on a cross-rope configuration

On the other hand, the main concern in HVDC lines, as mentioned before, is the performance under severe pollution conditions. Inverted-V, -T and -Y sets are mostly applied as “pollution” sets in cases where the tower to conductor clearance is limited but the pollution conditions on-site require high insulation length for accommodation of high creepage distances. Arcing Protection Compact tower top geometries make it even more important that design of power arc protective fittings considers orientation of their end burning points and the effect of electrodynamic forces that should guide the power arc in such a way that it burns on the end points designed for that purpose. Power arc tests on the complete insulator set (e.g. as described in [15]) may prove the protection concept (Fig. 4.12).

4.4.2 Mechanical Aspects Compaction will, in most cases, lead to tangent supports that restrict conductor movement and avoid flashovers by a suitable arrangement of the insulator set. The aim is to reduce the Right of Way (ROW) and/or the height. Common arrangements are [16]. • • • • • •

V arrangements Inverted V and T sets Y assemblies Semi-anchored sets Horizontal post insulators Insulated cross-arms (rigid and pivoting horizontal V sets).

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Fig. 4.12 V-string power arc test (great angle with additional arc protective fitting at the crossarm)

For all of them, the design regarding strength of the components should carefully consider the actual loading according to the resulting geometric sum of loads: • in the vertical direction from self-weight of the conductor (weight span) and additional ice load acting on the weight span, • in the horizontal direction perpendicular to the line from wind load on the wind span and, if applicable, a component of conductor tension in case of an angle tower, • in the horizontal direction along the line from horizontal conductor tension (the full tension in case of tension towers and possibly loads from load cases that include differential loads in case of suspension towers). As revised in the above sections, all these loads put the insulators under different solicitations, which depend on the arrangements. In general, compression solicitations become critical in the insulation and hardware design. More details on calculations can be found in [17]. As to coordination of strength of components, the same rules apply as for conventional lines, and hardware components should be designed such that they are more reliable compared to towers, foundations, conductors, and insulators. The requirements and tests of hardware depend on the national standards and the specification of the grid operator and differ not generally of standard lines. The case studies in this book give examples of design and specific testing.

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Fig. 4.13 420 and 110 kV V-strings (acute-angled)

V Arrangements V-strings configurations have been used widely to control the movement of the conductors at suspension towers and reduce horizontal “blow-out”. In general, they are set transverse to the line direction, and there are several examples using different insulation types (glass, porcelain, composite), different angles, symmetric and asymmetric (Figs. 4.13, 4.14 and 4.15). Inverted V and T Sets Inverted V sets are applied as “pollution” sets in cases where the tower to conductor clearance is limited but the pollution conditions on-site require high insulation length for accommodation of high creepage distances [18]. This is particularly interesting for compact DC lines, as the pollution performance requirements are often the limiting factor for insulation. For example, it can occur in replacement projects, where conventional glass or porcelain disk insulators failed due to pollution flashover and must be substituted by silicone rubber composite insulators. Figure 4.16 shows how inverted V sets are applied for DC. This set increases the pollution performance since much more creepage distance can be designed for the insulators. Similar effects can be achieved by T sets. Y Assemblies Y-sets or assemblies have been used in compact lines both for AC and DC projects to limit the conductor displacement at suspension towers and therefore reduce the horizontal distances. For example, an AC voltage upgrading project in Germany

4 Phase/Pole Configuration, Conductor and Hardware Fig. 4.14 420 kV V-string (normal angle)

Fig. 4.15 420 kV asymmetric V-string on the right side

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Fig. 4.16 Inverted V and T (pollution) sets for the accommodation of very high creepage distance on “limited” tower clearance for 533, 560 and 600 kV DC application [18]

applied this configuration to increase the voltage from 245 to 420 kV, using the same tower cross-arm structures. Figure 4.17 shows this example. The Y-set limits the swivel of the string and therefore the clearance (conductor to tower) is secured. In some cases, compromises regarding lower BSL levels (for example 950 kV instead of 1050 kV) must be accepted. For DC, Y-shaped suspension insulator strings have been applied to shorten tower cross arms and reduce horizontal distance between main conductors. Figures 4.18 and 4.19 show an example for 500 kV in Japan. Based on the results of case study and various tests (such as pollution withstand voltage characteristics, swinging characteristics and tensile strength test of insulators by full-scale test facility), the angle of the V-part of the Y-shaped strings has been set to 110°. Forty-two insulator discs are required for the V-part and twenty for the I-part per each Y-shaped string as the most optimum structure in the heaviest polluted area. This leads to the reduction of the cross-arms width and horizontal distance between main conductors.

Fig. 4.17 Y-set for line upgrading 245–420 kV AC with BSL of 950 kV [18]

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Fig. 4.18 Case study for the structure of Y-shaped insulator strings

Fig. 4.19 Y-shaped suspension insulator strings

Semi-anchored Sets Semi-anchored sets have been used in overhead power lines for more than 30 years, particularly in cases of line uprating. A rigid insulating structure is formed to avoid any kind of swivelling of the insulators. One example is shown in Fig. 4.20. Other arrangements and assemblies may be considered in order to reduce the phase to phase or pole to pole distances and minimize both height and line Right

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Fig. 4.20 Semi-anchored set consisting of a compression and a double tension insulator string

of Way. But a global analysis must be considered, including electrical aspects, insulation coordination, lightning protection, mechanical considerations, coronarelated limits, etc. Horizontal Post Insulators Porcelain horizontal post insulators have been used for a long time proving a good performance and helping for a better line acceptance. The development of composite insulators has increased the use of horizontal post insulators massively in recent years [16]. One of the most important aspects of this arrangement is the bending load to which the post insulator is subjected. This is a key aspect in the insulator design (Fig. 4.21). Another important advantage is the reduction of the height to which the horizontal wind force from the conductors is applied to the tower, compared to conventional I-string design. This configuration reduces the bending moment to the tower and foundations caused by horizontal wind, allowing optimizing the overall design. To reduce the vertical load on the horizontal post insulator, some designs include vertical long rod insulators, forming a suspended line post insulator design (Fig. 4.22).

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Fig. 4.21 Horizontal post insulator

Fig. 4.22 Suspended line post insulator

Insulated Cross-Arms Compact lines have started to become more popular with the widespread introduction of composite insulators [16], mainly because insulated cross-arms have to withstand a considerable compression load and are subjected to large deformations, for which composite materials are more appropriate than conventional ones, like porcelain or glass. The use of insulated cross-arms can reduce both the height of the line as well as the horizontal occupation (the horizontal movement of the suspension string is eliminated, reducing the conductor blow-out movement). The principle of the insulated cross-arms is based on the suspended line post insulator design. The suspension string (brace) is fixed directly to the tower to avoid the metallic crossarm (see Fig. 4.23). The post insulator works under compression, which makes it critical in the design, and the brace works under tension.

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Fig. 4.23 Horizontal (pivoting) V assembly [18]

The insulated cross-arms can be rigid or pivoting, depending on how the post insulator is fixed to the tower. In both cases, the mechanical performance is a major concern, due to the high loads transmitted to the insulators. In general, the vertical loads are taken mainly by the brace, and the horizontal loads are taken mainly by the post, which is loaded in buckling when these loads are compression loads. This makes the design of the post insulator a critical aspect, for which different solutions have been developed, like parallel posts, large rod diameter or hollow core insulators. In the pivoting cross-arms, the longitudinal movement of the conductors is allowed by using rotating connections, which allows the assembly to rotate about an inclined axis (inclined to create a restoring force when deflected). The horizontal fixed (non-pivoting) base assembly is needed in towers that have to accommodate longitudinal loads (e.g. angle towers). Some national standards request this type of assembly in case of road or railway crossings. The longitudinal load performance depends strongly on the post diameter and on the geometry of the

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Fig. 4.24 Fixed base horizontal V assemblies [18]

assembly. For high longitudinal loads (such as in the case of conductor breakage) the post insulators may be arranged horizontally in V shape Fig. 4.24. Interphase Spacers Interphase spacers are another element used for compact lines. They are applied to avoid clashing and/or flashovers during conductor galloping and to secure the clearance between conductors (Fig. 4.25).

Fig. 4.25 Interphase spacers

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Tower Designs

The tower types that can be used for compaction are many and varied. In general, compared to those used in conventional lines, the towers are typically either narrower or lower, or both, due to the much smaller distances between phases or poles. One characteristic is that the use of insulated cross arms and phase to phase or pole to pole insulation may be more prevalent than on non-compact lines. Insulator types can be any of the commonly used materials such as porcelain, glass, or composite. Composite may be the preferred option in phase to phase or pole to pole insulation due to weight and length considerations. Towers may be separated into those with tower body between the phases or poles and those without. The diagram below indicates some options (Fig. 4.26). Similarly, in DC, for the commonly used bipole with metallic return, the towers can also be classified depending on the position of the body with respect to the two poles, as shown in Fig. 4.27. Other schemes may have different considerations.

4.5.1 Tower Design Considerations With regards to overhead power line compaction, tower design can be divided into two parts: Tower body type selection and Tower top geometry. Tower Body Type Selection Tower body is generally chosen according to visual impact and land occupation restrictions. Although there are other options, the most used worldwide are: • Broad base lattice towers with separate foundations. • Narrow base lattice towers with compact foundation.

Fig. 4.26 AC tower designs with phases separated by structural elements and without [19]

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Fig. 4.27 Examples of tower arrangements for DC

• Single pylon with compact foundation (Figs. 4.28 and 4.29). From a compaction perspective the last two reduce land occupation to the minimum possible levels. Guyed towers are also commonly used, and, although the base is quite narrow the land occupation of the guys must be considered. Regarding the towers that surround the phases or poles, the most typical are those using two narrow base lattice towers with compact foundation. Tower Top Geometry Tower Top geometry has been extensively studied previously and is one of the key factors when line compaction is needed as phase to phase (or pole to pole) distances and phase to ground (or pole to ground) distances are involved. Most of the areas that need to be considered when defining tower top distances are covered in [20]. Therefore, hereinafter a summary of the main will be presented, focusing on minimum requirements and relation with line compaction.

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Fig. 4.28 Broad base lattice tower, separate foundations/narrow base lattice tower, compact foundation Fig. 4.29 Single pylons with compact foundation

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The main distances requirements when designing a tower top geometry can be summarize into electrical, maintenance and environmental. • Electrical requirements. Are the primary input for tower top distances. Based on phase to phase (pole to pole) or phase to ground (pole to ground) according to the voltage level, values can be obtained from national regulations or from a flashover reliability study. The latter is the preferred choice if a high degree of compaction is needed. Details and procedures can be found in [20], where also a comparative of different countries regulation and practices is presented. • Maintenance requirements. Tower top maintenance works such as tower painting often require bigger distances than those that come purely from electrical requirements. Normally a climbing corridor is required, and this must be considered as shown in Fig. 4.30. If live line work is expected, additional distances may need to be considered. More details can be found in Chap. 5. • Environmental requirements. In some countries, environmental regulations require additional distances to be observed in order to protect birds or other wildlife from electrocution. This may end up with a limitation in the degree of compaction that is achievable, especially for lower voltages overhead power lines. To provide an example, Table 4.7 contains the phase-to-ground distances included in the Spanish electrical regulation. Second column shows phase-toground distances, and the third column shows the minimum phase-to-ground distances when bird electrocution protection is involved. Fig. 4.30 Clearances considered, including climbing corridor

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Table 4.7 Clearances for birds used in Spain

Voltage (kV)

Dp-e (m)

Dp-e_birds (m)

400 kV

2.80

1.5

220 kV

1.70

1.5

132 kV

1.20

1.5

66 kV

0.70

1.5

As can be seen, for 132 and 66 kV overhead power lines the compaction limit comes from the environmental regulations and not from the electrical flashover reliability.

4.5.2 Tower Design Options Figure 4.31 indicates a few of the tower design options that may be considered for AC compact lines. For DC, Fig. 4.32 shows some of the tower design options:

Fig. 4.31 Different AC compact tower types for consideration

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Fig. 4.32 Examples of DC tower designs

4.5.3 Other Considerations for Tower Compaction The increasing restrictions on visual impact, land occupation and environmental concerns have enhanced the development of compact and low-profile designs. These designs need to be reliable and economically competitive. In general, lower height implies greater number of towers, although with lower load requirements. Therefore, an overall design assessment is needed, considering that in many cases the alternative to a line or a portion of line can be an underground cable. The following are some additional aspects that may intervene in the compact tower design:

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• Aesthetics. Certain tower designs achieve more acceptability in general for the public, although it is a subjective perception. There are a lot of references of aesthetic tower design in the literature, and the options are infinite [21]. • Materials. Use of new materials for towers (non-metallic, for example [22]), or new methods of construction (pre-manufactured or modular, for example, allowing interchangeability of components) This can be applicable to smaller towers, like lower voltage levels, requiring lighter machinery and easier assembling. • Maintenance. Considerations for regular maintenance to match certain requirements (particularly in shared corridors), like special machinery to be used in rail-side or road-side lines, etc. • Environment. Designs to include certain environmental requirements in particular locations. • Life cycle assessment (see Chap. 1).

4.6

Anti-galloping Considerations

Compact constructions of overhead power lines require preservation of minimum air clearances distances between phase conductors and between phase conductor and groundwire to avoid flashover. That applies for normal operation and exceptional occurrences, e.g. galloping. Compact lines are mostly designed with or close to minimum allowable conductor clearances. Rigid interphase spacers incorporating composite insulators properly distributed along spans are an option to preserve distances in spans and to keep the compact appearance. Conductor galloping is the name that has been used to describe the large amplitude (several meters), low frequency, wind-induced oscillation of conductors. Galloping occurs at single conductors as well as at bundle conductors mostly when they are ice covered because of the modified aerodynamic characteristic of the conductor. Galloping is an aeroelastic instability: aeroelastic because its occurrence depends on not only the aerodynamic characteristics of the conductor—or bundle—but also on its mechanical properties, characterised by the distribution of mass, stiffness, and damping. It is an instability because, if the conductor is restrained, no fluctuating aerodynamic force of the relevant frequency is found to be acting on the conductor: only if the conductor moves is such a force present. This distinguishes it from phenomena such as aeolian vibration or turbulent buffeting where, in general, a fluctuating force does act on a stationary conductor. Being an instability, galloping can occur over a wide range of windspeeds once the minimum critical speed had been exceeded: the typical windspeed range is 8–30 m/s [23]. The effects of galloping on a line are dependent on the severity and duration of the event and on the type of line construction. The most common problem that it causes is phase to phase flashovers since the amplitudes can approach the sag of

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the span (Fig. 4.33) and this can cause a failure of the line. But not only flashovers are a danger for the reliability of overhead power line. The heavy additional loads can damage the conductors, towers, insulators, and fittings. It should be ensured that the compact overhead power line can handle these additional loads, or these should be prevented. The susceptibility of compact lines to galloping is not different to that of conventional lines. Some investigations concluded that conductor bundles are more prone to galloping than single conductors, and the larger bundles less than smaller bundles. If galloping shall be accounted for in clearance design, [25] proposes ellipses predicting excursions of conductors during galloping. As increasing conductor clearances would be counter-productive in compacting lines, means can be sought to prevent or mitigate the effects of galloping. Reference [25] describes anti-galloping devices and methods to prevent galloping. The use of these devices may cause additional loads, which should be considered in the line design. The most widely used galloping control device is the interphase spacer (Figs. 4.34 and 4.35).

Fig. 4.33 Examples of galloping mode shapes [24]

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Fig. 4.34 345 kV twin bundle interphase spacer

Fig. 4.35 420 kV quad bundle interphase spacer

Compact constructions of overhead power lines require preservation of minimum air clearances distances between pole conductors and between pole conductor and metallic return to avoid flashover. That applies for normal operation and exceptional occurrences, e.g. galloping.

4 Phase/Pole Configuration, Conductor and Hardware Table 4.8 Galloping reported cases versus number of loops [26]

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No of loops

Phase conductor

Groundwire

1

42

2

2

26

3

3

34

6

2

1

4 or more

Galloping is a low frequency and high amplitude (several meters) wind induced oscillation of conductors. Both single and multiple loops of standing wires per spans had been observed on overhead power lines previously. In general, galloping is usually caused by steady crosswind acting on the asymmetrically iced conductor. However, it is worth noting that some cases of motion similar to galloping have been reported where ice is not involved. For example, the crossing of the River Severn in Great Britain is one example of ice-free galloping event. In this case, the conductor round wires presented a slightly asymmetrical cross section to the oblique wind which causes the instability. The effects of galloping on a line are dependent on the severity and duration of the event and on the type of line construction. It may have a major impact on the design of overhead power lines, both for clearances and in some cases tower load. The sufficient mid-span clearance between conductors is required to avoid contact or flashover between conductors, which are the most common effects of galloping. Large, repeated load variations may occur between phases and even between each side of a given tower, causing horizontal and vertical bending as well as torsional load on towers and cross-arms. Galloping is usually in one of two basic forms, standing waves and traveling waves, or a combination of them. The number of loops in a span varies between different reported causes significantly. Data on observed galloping of operating lines is shown in Table 4.8. To prevent the galloping, several control methods have been utilized which can be classified into three major categories: • De-icing or ice removal systems on the conductors. • Interfering with galloping mechanisms to prevent galloping from building up. • Rugged tower design to withstand such extreme weather event. T-2 Conductors The T-2 conductor, introduced in the 1980s, is designed to reduce the wind-induced motions including galloping. This type of conductor is essentially made of two smaller ACSR or AAC conductor and twisted together with a lay length of about 2.7 m. The conductor was evaluated in the field tests in Texas and Illinois. Over twoyear period, totally eight galloping events had been recorded on the round strand conductor but no galloping happened on the T2 conductor. T2 conductor has been used in USA and Denmark with mixed results (Fig. 4.36).

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Fig. 4.36 T-2 conductor

Interphase Spacers Interphase spacer is an insulating device to prevent the phase-to-phase contact during galloping. This method will not prevent galloping but force the motion into a model in which flashovers is much less likely if the spacers are properly distributed along spans. They usually incorporate composite insulators due to their light weight and mechanical properties. Figure 4.37 shows a double exposure of a usual double loop galloping on a span of a vertical circuit fitted with four interphase spacers. This shows that galloping motion can occur, but the spacers maintain the phase separation and minimize the likelihood of phase-to-phase contacts. Air Flow Spoilers Air flow spoiler is a device to modify the shape of the conductor so the total aerodynamic forces acting on the conductor along the line will be different. The idea is similar as T2 conductor but can be installed on any regular conductor as retrofit solution. An example is shown in Fig. 4.38.

Fig. 4.37 Example of using interphase spacer to prevent galloping [27]

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Fig. 4.38 Air flow spoiler [24]

Fig. 4.39 Example of torsional control device for twin bundle conductors [28]

Torsional Control Devices Torsional control device is a tuned torsional spring and inertia system to control the galloping of conductor. The torsional natural frequency is tuned to either first or second mode torsional frequency of the span. Several forms of torsional control devices are available. Figure 4.39 shows one of the examples developed in Japan for such application. Other solutions and devices to control galloping can be found in [25]. For compact lines, even though these exceptional loads originated by galloping are considered in the design of all the line components, it is important to prevent the occurrence of galloping events to avoid flashovers, due to the reduced distances.

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References 1. CIGRE Technical Brochure 278. The influence of line configuration on environment impacts of electrical origin. WG B2.06, Paris (2005, Aug). www.e-cigre.org 2. CIGRE Technical Brochure 638. Guide to overall line design. Working Group B2.51, Paris (2015, Dec). www.e-cigre.org 3. CIGRE Technical Brochure 63. Guide to procedures for estimating the lightning performance of transmission lines. WG 33.01, Paris (1991, Oct). www.e-cigre.org 4. CIGRE Technical Brochure 388. Impacts of HVDC lines on the economics of HVDC projects. Joint Working Group B2/B4/C1.17, Paris (2009, Aug). www.e-cigre.org 5. Santos, M.L., Jardini, J.A., Casolari, R.P., Arnez, R.L.V., Saiki, G.Y., Sousa, T., Nicola, G.L.: Power transmission over long distances: economic comparison between HVDC and halfwavelength line. IEEE PWRD (2013) 6. CIGRE Technical Brochure 695. Experience with the mechanical performance of nonconventional conductors. Working Group B2.48, Paris (2017, Aug). www.e-cigre.org 7. CIGRE Technical Brochure 426. Guide for qualifying high temperature conductors for use on overhead transmission lines. WG B2.26, Paris (2010, Aug). www.e-cigre.org 8. CIGRE Technical Brochure 273. Overhead conductor safe design tension with respect to Aeolian vibrations. Task Force B2.11.04, Paris (2005, June). www.e-cigre.org 9. Lillien, J.L., Snegovski, D., Capelle, T., Du, M.L.: Limiting windstorm effects on tower by a low-drag conductor. CIGRE paper B2-312, Paris Session (2004, Aug). www.e-cigre.org 10. IEC 60826. Design criteria of overhead transmission lines. International Standard, IEC 60826, 3rd edn (2003, Oct) 11. IEC TR 61774. Overhead lines—meteorological data for assessing climatic loads. Reference number CEI/IEC 61774: 1997, Geneva, Switzerland (1997) 12. Li, Q., Rowland, S.M., Shuttleworth, R.: Calculating the surface potential gradient of overhead power lines. IEEE Trans. Power Deliv. 30(1), 43–52 (2015) 13. Kiessling, F., Nolasco, J., et al.: Overhead Power Lines, 1 edn. Springer, Berlin (2003). ISBN 3-540-00297-9 14. Regis, O., et al.: Expanded bundle technique: the application of HSIL TL concept to increase capacity of overhead lines. CIGRE Paper 22-207, Paris Session (1998). www.e-cigre.org 15. IEC 61467. Insulators for overhead lines—insulator strings and sets for lines with a nominal voltage greater than 1000 V—AC power arc tests, Geneva (2008) 16. Papailiou, K.O., Schmuck, F.: Silicone composite insulators. In: Power Systems. Springer, Berlin (2013). https://doi.org/10.1007/978-3-642-15320-4_4 17. Schmuck, F.: Solutions for line compaction using composite insulators: review of current situation and future outlook. In: 2015 INMR World Congress Munich, Germany (2015, Oct) 18. Lehretz, F., Seifert, J.M., Troppauer, W.: Compact OHTL insulation—future trends and technologies. Paper 54. CIGRE-IEC International Symposium, Cape Town (2015, Oct). www.ecigre.org 19. Fife, B., Calamari, D.: 500 kV challenges in congested areas. In: Power Engineers Conference, Sun Valley (2017, Mar) 20. CIGRE Technical Brochure 348. Tower top geometry and mid span clearances. WG B2.06, Paris (2008, June). www.e-cigre.org 21. CIGRE Technical Brochure 416. Innovative solutions for overhead line supports (annex). Working Group B2.08, Paris (2010, June). www.e-cigre.org 22. CIGRE Technical Brochure 818. Transmission line structures with fiber reinforced polymer (FRP) composite. WG B2.61, Paris (2020, Nov). www.e-cigre.org 23. Tunstall, M.J., et al.: Field observations of overhead line galloping. CIGRE Report. WG 22.11, Task Force on Galloping. ELECTRA Nr. 162, Paris (1995, Oct). www.e-cigre.org 24. ELECTRA Article 191_2. Review of galloping control methods. Task Force B2.B11 (2000, Aug). www.e-cigre.org

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25. CIGRE Technical Brochure 322. State of the art of conductor galloping. Task Force B2.B11.06, Paris (2007, June). www.e-cigre.org 26. EPRI Transmission Line Reference Book. Wind-Induced Conductor Motion (Orange Book). Palo Alto, California. Ed. (2008). www.epri.com 27. Pon, C.J., Havard, D.G., Edwards, A.T.: Performance of interphase spacers for galloping control. Ontario Hydro Research Division Report No.82-216-K (1982, July 6) 28. Fujii, Y., Koyama, T., Sawamoto, T.: Countermeasures against conductor galloping. Paper 11. Colloquium Environmental Impact of OHL in Japan. CIGRE SC22. Sendai Meeting (1997). www.e-cigre.org

5

Live Line Maintenance Techniques

Contents 5.1 5.2 5.3

5.4 5.5

5.6

5.7

Feasibility of Live Line Work on Compact Line . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Difference Between HVAC and HVDC Live Line Work . . . . . . . . . . . . . . . . . . . . . . . . . . . Minimum Approach Distance (MAD) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 5.3.1 Minimum Approach Distance (MAD) for HVAC . . . . . . . . . . . . . . . . . . . . . . . . . . 5.3.2 Minimum Approach Distance (MAD) for HVDC . . . . . . . . . . . . . . . . . . . . . . . . . . Control of Transient Overvoltage . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Live Line Work Methods for Compact Lines . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 5.5.1 Hot Stick (or Distance) Method . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 5.5.2 Barehand Method . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 5.5.3 Use of Robots . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Additional Considerations . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 5.6.1 Job Planning . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 5.6.2 Non-ceramic Insulators (NCI) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 5.6.3 Tools and Equipment . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Procedures Used by Utilties . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 5.7.1 Manitoba Hydro (Canada) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 5.7.2 Kansai Electric Power Co. (Japan) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 5.7.3 Electric Power Development Co. (Japan) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 5.7.4 Eskom (South Africa) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .

104 105 106 106 107 109 111 111 113 115 117 117 117 119 119 119 123 124 126

Abstract

The principle to perform live line work on compact lines is no different to a conventional one. However, actual live line experience with compact designs is still limited. This design should consider live line work requirements during the early stages, to maintain the minimum approach safety distance (MAD), as it might become one of the governing design parameters of a compact line. The major differences between compact and conventional line live work can be summarized as: (1) Reduced electrical clearance. (2) More complicated insulator configuration. (3) Extensive use of Non-Ceramic Insulators (NCI) or composite © Springer Nature Switzerland AG 2024 R. Stephen and J. Iglesias (eds.), Compact Overhead Line Design, Compact Studies, https://doi.org/10.1007/978-3-031-44524-8_5

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insulators. This chapter revises the methods and techniques used for live line work on a compact line, the tools, the theory, the control of overvoltages and the experimental practices used by different utilities around the world, analysing the differences between HVAC and HVDC lines and other considerations to be taken into account.

5.1

Feasibility of Live Line Work on Compact Line

The requirement of live line work is constantly increasing due to the power system constraints and the significant outage costs. Live line work has proven through its history to be one of the safest methods of maintaining the transmission and distribution systems. This safety record is a direct result of the careful planning, training and preparation undertaken prior to the commencement of all live line work. All live line work utilizes one of the following methods: • Using special tools attached to the ends of insulated sticks, the worker maintains minimum safe approach distance (MAD) from the energized conductor or apparatus. Also referred to as “Hot Stick” or “Distance” method. • Using insulated tools or equipment and wearing conductive suits and boots, the worker is brought into contact with energized line and apparatus by various means of access (ladders, ropes, insulated aerial platform, helicopter), thus eliminating the hazard of different potentials while maintaining the required minimum approach distance (MAD) This practice is referred to as “Barehand” method. For additional information, refer to [1–3] (Fig. 5.1). Fig. 5.1 Live line work

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Line design plays a significant role in the possible implementation of live line work on compact lines. Designers should incorporate the required minimum approach distance (MAD), anchor and lifting points and consider additional mechanical loading on certain parts of the tower during live line work. Utilization of live line friendly hardware assemblies is critical to facilitate live line tooling. As the electrical clearances of compact lines are smaller than conventional lines and, in some cases, it might be even smaller than the standard MAD, every compact line would require a case-by-case study to determine the feasibility of live line work. Some special tools or additional mitigation method might be required to perform the live line work on compact line. These could include: • Displacement live conductors on the compact tower with the use of insulated sticks to ensure the required minimum approach distance (MAD) requirements can me adhered too. • Reducing the required minimum approach distance (MAD) requirement by controlling the over voltage at the work site by means of a voltage control device (personal protective gap and/or surge arrestors) • Reducing the ergonomic distance allowance to zero by means of restrictive barriers.

5.2

Difference Between HVAC and HVDC Live Line Work

Live line work on HVAC line has been carried out since the 1930s and several research and testing have been done for different voltage class of HVAC systems to qualify tools and work methods. Several international standards for HVAC are available based on experience and knowledge gained from testing. However, a similar standard is not available for HVDC live line work. In most cases, the results based on HVAC system were carried over to HVDC applications. The design principles considered the following fundamental assumption: DC pole-to-ground voltage is equal to AC line-to-ground peak voltage. One principal difference is the space charge generated by steady state corona present around the head of a live line tool during the work. Physical differences between AC and DC corona, combined with the fact that HVDC systems are characterized by unidirectional static electrical fields will certainly result in a different space charge distribution for HVDC systems than that present for HVAC systems [4]. Unlike HVAC system, utilities must consider corona effects and space charge effects prior to undertaking any live line work on HVDC lines. To perform live line work in a safe manner, the following criteria should be considered: • The leakage current through the body should be less than 1 mA (perception limit),

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• The maximum electric field on the body of live line crew should be less than 240 kV/m, • MAD should be maintained during live line work.

5.3

Minimum Approach Distance (MAD)

The minimum approach distance (MAD) is the sum of two components: • The electrical distance, often referred to as the Minimum Air Insulation Distance (MAID), which is based on the withstand/spark-over of the air gap and the anticipated overvoltage value at the worksite. • An ergonomic distance of typically 0.2–0.7 m for system voltage from 72.6 to 800 kV which is added to cater for inadvertent movement of the live worker. The electrical distance component of the MAD is predominantly influenced by the anticipated overvoltage at the worksite. Two types of overvoltage need to be considered: • Temporary Overvoltage (TOV), and • Transient Overvoltage. Transient overvoltage includes both switching and lightning overvoltage. Because lightning induced overvoltage is not quantifiable, the common rule is to stop work when there is an unfavourable weather forecast or when lighting is seen, or thunder is heard in the vicinity of the worksite. Therefore, only switching overvoltage need to be considered to calculate MAD. The control of the switching overvoltage is discussed in following chapters.

5.3.1 Minimum Approach Distance (MAD) for HVAC The overvoltage factor of an AC line is the ratio of the transient overvoltage to the peak line-to-ground voltage of the line. When the value of the overvoltage factor is unknown for the specific worksite, the industry-accepted value or the maximum anticipated value from national code shall be used in this case. The typical values from [5] are listed as follow (Table 5.1). However, this practice might prevent live line work on compact line designs due to additional safety buffer. It is recommended that a detailed transient overvoltage study is conducted for each compact line and then using this actual overvoltage factor to determine the required MAD.

5 Live Line Maintenance Techniques Table 5.1 Overvoltage factors

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AC line-to-line voltage (kV)

Overvoltage factor (p.u.)

At and below 362

3.0

363–550

2.4

551–800

2.0

Calculation of MAD follows the same procedure for conventional and compact line. Currently there are two widely accepted methods to determine MAD in AC lines. These are: • The IEC Standard 61472 [6]. • The IEEE Standard 516 [5]. In addition, each individual country might publish their own specific national code or method to compute MAD.

5.3.2 Minimum Approach Distance (MAD) for HVDC As mentioned before, the actual live line experience with compact DC lines is still scarce. Only a few utilities have attempted it so far, and standards like those used for HVAC lines are not available for HVDC live line work. To determine the MAD, two methods have been followed, as detailed below. Theoretical method The MAD for HVDC live line work can be determined based on the assumption of direct equivalence between the DC pole-to-ground voltage and AC line-to-ground peak voltage. The overvoltage factor of the HVDC system is typically assumed to be 1.8 p.u. An engineering evaluation should be always performed to confirm the overvoltage factor of a particular project. In some projects, the actual overvoltage factor is higher than 1.8 p.u. According to [5], three values for the MAD in HVDC lines at different work situations can be derived from the following equations:

where

DMAD = (C1 + a) × V p−g × T × A + M

(5.1)

DMAD for Tools = (C1 × C2 + a) × V p−g × T × A + M

(5.2)

( ) DMAD-helicopter = (C1 + a) × V p−g × T × A + M × H

(5.3)

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DMAD DMAD for Tools

DMAD-helicopter C1 C2 a T A M H

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The minimum air insulation distance (MAID) plus a factor for inadvertent movement. The minimum length of insulation distance required, measured using the shortest distance between the conducting part at the live end and the closest point at ground potential. This term applies to tools that are subject to inadvertent movement. The shortest distance in air between an energized conductor and the closest point of helicopter. 0.01 ft/kV (60 Hz rod gap withstand). Typically, C 2 = 1.1 Adjustment ratio to compensate for air saturation expressed as a ratio of distance to kilovolts. The maximum anticipated p.u. factor. The altitude correction factor. The inadvertent movement factor. The helicopter factor for calculations in this guide (H is normally 1.10).

Experimental method Because the theoretical computation for MAD of HVDC is completely based on the testing of HVAC systems, a few DC related factors, such as space discharge, are still not fully understood at this moment. Thus, some utilities companies conduct their own tests to determine the actual MAD for their HVDC lines by using experimental method. Between 2010 and 2014, State Grid Corporation of China conducted several experiments to develop the live line work procedure and MAD for their newly built HVDC lines. The testing method and findings will be presented here as an example to show how to utilize experimental method to determine the actual MAD [7]. Simulated tower heads were made in the proportion of 1:1 based on the designed tower structures and the simulated insulator strings and multi-bundle conductors were the same as the design parameters of proposed HVDC line. The simulated man was made of aluminium alloy with the same morphology and structure to the real one. The typical test setup is shown in Fig. 5.2. All possible scenarios need to be examined in this case to determine the proper MAD. For State Grid Corporation of China ± 660 kV HVDC line, four different scenarios were examined which are illustrated in Fig. 5.3. The test was conducted at State Grid Electric Power Research Institute outdoor testing facility. Standard switching positive impulse with 250 μs rising time was used for entire testing. The test results are summarized in Table 5.2. The detailed finding of this test can be found in [7].

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Fig. 5.2 Typical test setup to determine MAD [7]

5.4

Control of Transient Overvoltage

As discussed previously, transient overvoltage is one of the key factors in the computation of MAD. Many experiences have shown that MAD calculated based on the industry-acceptable value of overvoltage factor present a challenge to perform live line work on compact line. Therefore, actual transient overvoltage study is required and some mitigation methods to reduce transient overvoltage at worksite may also be required. The focus is on switching overvoltage, as it is common practice to stop the work under unfavourable weather conditions that could originate any lightning overvoltage. Blocked automatic reclosing Blocking the automatic reclosing function on the line to be worked on eliminates switching overvoltage. This is widely used by most utilities for all live work. Pre-insertion Resistor (PIR) PIR could significantly reduce the transient overvoltage during line reclosing and energization. This is the most common mitigation method to reduce transients. A detailed study is necessary to properly size the resistor and it should be done under an overall line insulation coordination effort. The transient will be minimized if PIR is equal to line surge impedance in AC lines. Figure 5.4 demonstrates the effect of PIR on maximum switching overvoltage. Surge arresters Transmission line arresters are applied to overhead power lines to mitigate the effects of lightning. In some cases, they could be installed on overhead power lines to reduce switching surges magnitudes. When using surge arrester to control

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Fig. 5.3 Four test scenarios for ± 660 kV Yindong HVDC project Table 5.2 Summary of test results for ± 660 kV Yindong HVDC project Overvoltage p.u

Elevation (m)

U50 (kV)

MAD (m)

Scenario 1

1.75

0

1445

3.6

Scenario 2

1.75

0

1457

4.1 (S1 + S2)

Scenario 3

1.75

0

1447

4.0

Scenario 4

1.75

0

1442

4.5

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Fig. 5.4 Effect of breaker PIR on maximum switching surge overvoltage

switching transient, the potential switching surge energy of the system needs to be calculated and used to size the surge arrester. The surge arrester has been proven to be effective for both reclosing and fault condition. Portable Protective Air Gaps (PPAG) Portable protective air gaps can be installed on a compact tower to control the overvoltage at the work site to a pre-determined value and thereby reduce MAD requirement. These gaps are set to flashover at a predetermined reduced voltage and this voltage is then used to determine MAID. While PPAG’s have been used successfully it is not always a practically feasible option on certain towers and higher voltages.

5.5

Live Line Work Methods for Compact Lines

5.5.1 Hot Stick (or Distance) Method In this scenario, the live line crew is always at ground potential and performs the work by using an insulating tool. The insulation level of the insulating tool should maintain the minimal leakage current. MAD should be maintained all the time between live line crew and phase or pole conductors.

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The safety of live line work crew highly depends on the performance of live line work tools in this case. If the live line work tool is contaminated, the leakage current along the surface of the live line work tool will increase significantly. In some cases, the leakage current was beyond the safety criteria and caused electric shock. Therefore, the insulating tool used for primary employee protection shall be removed from service within pre-determined time and whenever required for examination, cleaning, repairing, and testing. The insulating tools must be wiped clean and visually inspected for defects before use each day. If any defect or contamination that could adversely affect the insulating qualities or mechanical integrity of the insulating tool is present after wiping, the tool must be removed from service and examined and tested before being return to service [8]. Meanwhile, a dedicated work gloves should be used to avoid introducing unwanted contaminations during the live line work. Details on the requirements for the equipment and best practices on this type of work can be found in [9]. As work is performed from a distance, hot stick live work should be feasible on most compact towers/lines, provided worker access can be facilitated and suitable live work friendly hardware have been installed (Fig. 5.5). In some cases, live component can be displaced to ensure MAD can be achieved (Fig. 5.6). For HVDC live line work, full body conductive suits and boots are usually required due to large electrical field. Figure 5.7 shows this method on an HVDC line.

Fig. 5.5 Hot stick technique from tower

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Fig. 5.6 Displacing of live jumper to achieve access and maintain MAD

Fig. 5.7 Hot stick method from a ladder for insulator replacement on HVDC line

5.5.2 Barehand Method Barehand Method has been used to perform much live line work for years. In some cases, it becomes the only option since the Hot Stick Method is not feasible due to the design of overhead power lines. The principle of the Barehand Method is to maintain the body of the live line crew at the same electric potential as the phase or pole conductor. That way the current flow through the body is minimal.

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Fig. 5.8 Insulated aerial platform used for Barehand Method on HVAC line

The critical step of the Barehand Method is when the live line work crew is in transition to and from the worksite. MAD must be always maintained during this transition. There are different means to move and maintain the worker at the phase or pole potential. The most used are insulated ladders, ropes, insulated aerial platforms and helicopters. Reduced clearances and/or inability to access and achieve the required MAD due to the tower design are aspects that limit the use of the Hot Stick Method. In these cases, working from elevated insulated platform or insulated ladder may be possible utilising barehand technique as indicated in the Figs. 5.8 and 5.9. The Ergonomic component of the MAD can be reduced to zero if a physical barrier is installed to eliminate inadvertent movement of the barehand live worker. In such case the MAID only will be applied. An example can be seen in Fig. 5.10. The Barehand Method on high voltage overhead power lines requires the use of conductive suits and boots, on HVDC lines, where unidirectional static electrical fields may result in a pronounced space charge distribution surrounding the conductors (Fig. 5.11).

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Fig. 5.9 Insulated ladder used for Barehand Method on HVDC line

5.5.3 Use of Robots The use of robotic arms controlled from ground level is a technology that has started to be implemented by some utilities [10]. It is expected a development of the applications of the robotics to the live line work in the future. One of the uses of the robotic arms is the displacement of live conductors thereby creating additional clearance so that the minimum approach distance (MAD) can be achieved. An example can be seen in Fig. 5.12, where a robotic arm is used to displace live conductors after they were disconnected from the live end of the insulator string using typically Hot Stick technique from an insulated aerial platform.

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Fig. 5.10 Use of a physical barrier on strain stick to maintain MAD (5.5 m for a specific 765 kV AC line) with a MAID of 5 m

Fig. 5.11 Insulated aerial device and conductive suit for Barehand Method on HVDC line

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Fig. 5.12 Quanta Linemaster® robotic arm used to displace live conductors

5.6

Additional Considerations

5.6.1 Job Planning Job planning must be conducted before any live line work. Different utilities might have different requirement which ties to their own standard procedure or national code. The common considerations widely accepted by many utilities are listed as follow: • Always verify if the live line crews have adequate training and certifications. • Written work procedure in accordance with national and utility requirements. • Advance notice for switching arrangement with System Operator for the mitigation method such as blocked reclosing. • Live line work must not be started during rain, melting snow, sleet or heavy fog or when lightning is seen or thunder is heard. • Ensure there is a rescue plan in place.

5.6.2 Non-ceramic Insulators (NCI) Many compact line designs make use of NCI. Unlike glass cap and pin insulators, the electrical and mechanical integrity of an NCI cannot be determined by visual

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inspection. This poses a risk during live line maintenance activity because of both mechanical and electrical failure while work is in progress. Some utilities merely perform visual inspection while other prohibits live work on NCI’s. This will be influenced by the failure rate you have experienced and the associated risk. Research has spent much time and effort developing an in-situ device for determining the health of a NCI insulator. Below can be seen the typical steps to follow: • The operator positions himself and presses the push button on the probe and the logger (optional). • The tester is placed on the string a few insulators below the grounded end. • The tester is slid back to the beginning of the string and kept stationary for at least 10 s until a long beeping sound is heard. • The tester is slid to the line end of the string and then back to the starting point. The buzzer sounds each time a reading is taken at each insulator. • The tester is removed from the string by making sure a continuous sound is heard (indicating a successful scan) and then the push button is pressed to store the data. Commercially available testers can be applied by means of a hot stick to in service NCI’s to verify condition (Fig. 5.13).

Fig. 5.13 Scheme of the work for determining the health of NCI insulators

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5.6.3 Tools and Equipment The condition of the tools and equipment for live line work is essential for the safety of work crew. Any contamination on the tools or the equipment may increase the leakage current along its surface. Therefore, the requirements for examination, cleaning, repairing, and testing of these tools and equipment must be very strict. So do the work procedures and training of the crew. More details can be obtained in [8, 9]. Live line work tools, such as hot sticks, insulated ladders, cradles, etc., as well as the equipment and conductive suits and boots for compact lines are essentially the same as those used for conventional ones. However, as stated before, there are some particularities that apply to live work on HVDC lines due to the space charge distribution. The research conducted so far identifies some issues which may impact the performance of hot sticks when used on HVDC lines [4]. These issues need further investigation and work: • Investigation into the potential effects of corona generated space charge on the electric field distribution along the surface of live line work tools. • Explore potential differences in the withstand strength of live-line work tools under voltages composed of switching impulses superimposed on a steady dc bias voltage and switching impulse voltages alone. • Deposit charge on a live line work stick, and to examine the effect of this surface charge on the switching impulse withstand level of a charged live line work tool. More details on procedures recommendations on HVDC live line work can be found in [11].

5.7

Procedures Used by Utilties

5.7.1 Manitoba Hydro (Canada) Manitoba Hydro first began live line work in 1972 on their HVDC lines (Bipole I and II). A basic set of tools for suspension insulator changes was purchased at this time. Today Manitoba Hydro carries out live line work using hot sticks and other fiber glass reinforced tools, applies the barehand method using ladders, insulated aerial devices, conductor carts, and the helicopter method has also been applied. For all live line work maintenance at Manitoba Hydro there are various restrictions that apply. For HVDC lines, there are restrictions on weather conditions such as wind and humidity for stick work and barehand. There is the requirement for flame/arc resistant clothing and full conductive suits including conductive gloves, boots, and socks. A safety hold off is required for all HVDC line work such that restarts on the line are disabled. Clean stick gloves must be worn when handling fiber glass reinforced plastic (FRP) tools. If the barehand method is to be utilized,

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a barehand request must be submitted to the Live Line Methods Coordinator prior to performing the work. HVDC procedures require their own set of unique tools and in some cases, there is the requirement for specially designed equipment for the procedure and structure to be worked on. DC leakage meters are required for monitoring the ladders and insulated aerial device booms. DC potential testers are required for testing for potential prior to de-energize work. Highly trained and certified linemen are required for all live line work tasks. No live line work is permitted on HVDC lines from May through October as the HVDC system has been plagued by phantom trips with no apparent reasons. The trips occur during the warmer seasons and occur mostly in the Northern part of the line, later in the day, and usually follow rain events. For this reason, the newly built Bipole III project will include a three-bundle conductor configuration and longer insulation lengths to attempt to avoid similar issues. Insulators at Manitoba Hydro on our HVDC line have been sampled for contamination and the pollution has been very light. For all live line work Manitoba Hydro has the requirement that all insulators be inspected prior to live line work. There are minimum requirements on the number of allowable broken insulators. These recommendations were based on literature review and results of DC flashover testing in a high voltage laboratory. Manitoba Hydro experienced hot stick flashovers in 1997 and 2002 during insulator replacements at a 500 kV AC line. The findings from the research of these incidents showed that the root cause was salt contamination on the hot stick to which environmental conditions played a role. Manitoba Hydro now works with weather restrictions, clean handling procedures for all FRP tools, annual stick maintenance and testing, the use of dedicated clean hot stick gloves, polymer sheds on FRP tools and additional field supervision. Manitoba Hydro exceeds industry with the use of polymer sheds on FRP tools. The polymer sheds act as a limits of approach marker, increase the leakage of the FRP tool to aid in the prevention of pollution flashovers and will prevent streamer/charge-based flashovers which propagate along the surface of the tool. When Manitoba Hydro was investigating the 500 kV AC accidents, additional laboratory testing was completed for HVDC. A laboratory-based phenomenon was discovered and termed “fast flashover”. The fast flashover was characterized by occurring for direct voltages of negative polarity, at voltages less than system operating, at low relative humidity and occurs without warning in terms of elevated leakage current. The flashovers were shown to be eliminated using polymer sheds on the FRP tools as well by installing a specially designed and patented inhibitor electrode at the ground end of a hot stick or insulated aerial device boom. The fast flashover is a space charge-based phenomenon which was shown to occur in the laboratory environment where the FRP tool was precharged with negative DC voltage and then the voltage was ramped at 10 kV/s. For this reason, at Manitoba Hydro if an insulated boom is used to bond onto the HVDC conductor it must have a minimum of 17 feet of insulation and be fitted with four booster sheds and a specially designed inhibitor electrode (corona band shield) (Fig. 5.14).

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Fig. 5.14 Insulated aerial boom shown with sheds and inhibitor electrode

For HVDC work at Manitoba Hydro all universal sticks and other FRP tools where applicable have the requirement for being fitted with 3 polymer sheds equally spaced 1, 2 and 3 m from the hot end as well for the above reasons. Presently limits of approach for HVDC in industry such as those specified in IEEE-516 [5] are based on AC laboratory tests. IEC 61472 [6] does not provide any calculation methods for work on DC lines. There is research being undertaken by EPRI to determine the limits of approach distance specific to HVDC as well as the investigation of space charge on FRP tools. In the case of AC, the corona tends to stay very close to the conductor due to the alternating charges which oppose and attract. In the case of DC, the charge repels each other, and the corona causes a space charge to be spread into space in the vicinity of the conductor. The most common live line work maintenance activity on HVDC lines is insulator replacements on various towers, but also has included full damper replacement projects, conductor splicing/repair and conductor barehand inspections. Each Bipole line also includes ground electrodes. The ground electrode lines run from the converter stations as overhead distribution, insulated to 25 kV, to the electrode sites which are buried metal rings located within a section of land. While the DC line resistance is in the order of 15 Ω, the ground path resistance is in the order of 0.1 Ω. The electrode lines carry unbalance while in bipolar mode but are also capable of carrying full line current when in monopole mode. The voltages on the lines may exceed 100 kV for milliseconds but in general under bipolar steady state operation the voltage is much less than 25 kV. The electrode

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lines cannot be de-energized without taking out the complete Bipole and there is no protection for clearing faults. The groundwire on the electrode line is grounded only at the midpoint of each electrode line. It is floating everywhere else with an arc horn/groundwire giving clearance to ground at each tower. Given recent industry concerns and new requirements on arc flash, Manitoba Hydro has moved away from rubber glove work at structures on the electrode line to stick work. Barehand and or rubber glove work can still be performed away from structures (Fig. 5.15). Manitoba Hydro also carries out de-energized maintenance on our HVDC lines which come with their own unique properties due to the long lengths of parallel conductors. Although there are no induction concerns during steady state operation, when work is being performed on the de-energized pole a switching transient on the energized pole can cause an impulse transient which can be a hazard for workers. Workers are protected by Equipotential Bonding and Grounding Practices while working aloft. Special precautions are taken for work on the ground where the workers have the highest probability of being exposed to impulse transients from a fault on an energized pole. The de-energized HVDC must be always grounded to ensure that the static charge from parallel HVDC lines is drained off. The existence of parallel HVAC lines must be also considered as large loop currents can also exist or occur due to steady state operation or faults. Workers have complained of nuisance shocks while working on de-energized poles and this is likely due to the workers becoming charged from the energized poles. Since HVDC lines transfer large amounts of power, there are immense benefits to carrying out live line work. These benefits include, but are not limited to, avoiding revenue losses, maintaining grid reliability and stability, keeping the power flowing to customers, and avoiding the risks due to human operating errors which can be experienced during de-energized maintenance . Manitoba Hydro has performed live line work on HVDC lines for 40 years incident free. Only one incident occurred while working on HVDC lines de-energized. Manitoba Hydro experience and industry experience shows that live line work maintenance on AC and DC lines can be completed and is as safe as de-energized

Fig. 5.15 Electrode lines. Manitoba Hydro

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maintenance. At Manitoba Hydro and in industry research on all aspects of live line work continues to ensure that worker safety is maintained and ensured.

5.7.2 Kansai Electric Power Co. (Japan) In Japan, the Minimal Approach Distance (MAD) for HVDC can be determined based on the assumption of direct equivalence between the DC pole-ground voltage and AC line-ground peak voltage. For example, MAD for main line of DC ± 500 kV Kii Channel HVDC Link owned by Kansai can be considered as being equivalent to that of AC 613 kV (Table 5.3). MAD can be determined in consideration with mainly internal abnormal voltage and minimum distance for working. Also, standard distance is set as added 0.3 m to MAD which is desirable for safe work to occur. Kansai Electric has been operating 500 kV Kii Channel HVDC Link since 2000. Two kinds of live line work maintenance have been carried out so far. One is the detection of faulty insulator using hot sticks on the live line that are carried out every 20 years. There are three types of detection devices depending on the shape of insulator strings. One example is shown in Fig. 5.16. This is called self-weight type detector used for long V-shaped or long I-shaped insulator strings which can move down along insulators by its weight and detect faulty insulators one by one. It is generally used for long insulator strings because it is impossible for workers to lift up heavy hot stick with detector from arms. The other is the inspection of insulator strings using hot sticks with small-sized cameras on live line as shown in Fig. 5.17. Insulator near seaside areas tend to be Table 5.3 Minimal Approach Distance (MAD) in Japan Line

Owner

Voltage

MAD (main line/ return line)

Standard distance (main line/ return line)

Kii channel HVDC Kansai link

500 kV

3.5 m/1.15 m

3.8 m/1.45 m

250 kV

N.A

3.0 m/0.5 m

Hokkaido-Honshu HVDC link

J-Power

Fig. 5.16 Detection of faulty insulator for V-shaped insulator strings

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Fig. 5.17 Inspection of insulator strings by small-sized cameras

exposed to corrosive environment, but it is impossible to check visual condition of far insulators from arms. Accordingly, this device makes it possible to inspect rust or corrosion among all insulators by using four cameras which are set above and below insulators.

5.7.3 Electric Power Development Co. (Japan) Electric Power Development Co., Ltd. has used Automated Faulty Insulator Detector for DC ± 250 kV Hokkaido-Honshu HVDC Link. There are two types of detectors. One for tension insulator strings and the other is for suspension insulator strings. The detector is semi-self-propelled. It moves automatically from the insulator disc on the ground side to the same on the line side. After checking the last disc at the line side, it stops moving and the detector is retrieved by a line man drawing the insulated chain connected to the detector. Automated Faulty Insulator Detector measures the leakage current of each insulator discs. The data is converted to FM of 800 MHz and sent to the measuring instruments on the ground and displayed on that monitor. The inspector checks the leakage current and identifies the defective insulator disc (Figs. 5.18, 5.19, 5.20 and 5.21). Fig. 5.18 Pre-check and calibration of the detector

5 Live Line Maintenance Techniques

Fig. 5.19 Automated faulty insulator detector for tension insulator strings

Fig. 5.20 Automated faulty insulator detector for suspension insulator string

Fig. 5.21 Checking the leakage current displayed on the monitor

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5.7.4 Eskom (South Africa) Eskom operates and maintains the South African section of the Cahora Bassa 533 kV HVDC. The line connects the hydro generating plant at Songo in Mozambique to the Apollo converter station in Johannesburg, South Africa. The total line length is 1034 km, of bi-pole design on single lattice steel towers. Conductors are quad Zambezi and insulation consists of glass cap and pin insulation as well as silicone composites installed more recently. The typical tower of the line is shown Fig. 5.22. While the line was built in the 1970’s it was not fully operational for many years for various reasons. As a result, there was no maintenance requirement and Eskom thus has, considering the age of the line, limited experience in HVDC live line work maintenance. The line has become critically important in the last 10 years because of a shortage of generation capacity in South Africa. Pollution related insulation failure faults have been of concern and several live line work maintenance activities have been performed to improve the performance. Severe vandalism was also experienced on sections of the line resulting in multiple shattered glass insulators (Fig. 5.23).

Fig. 5.22 Cahora-Bassa 533 kV DC line

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Fig. 5.23 Multiple broken disks due to vandalism

Live aerial spray washing Line inspections indicated some areas of high pollution on glass cap and pin insulators. A helicopter-based insulator washing program was initiated to improve performance in the short term. A stock standard commercial aerial spray washing unit was utilized on a Bell helicopter. Normal AC spray washing requirements as far as water and techniques were concerned were applied (Fig. 5.24). Both strain and suspension assemblies were washed in high pollution areas and the performance of the line improved over the short term. Re-insulation As part of a long-term performance improvement a re-insulation project was initiated. Due to generation constraints it had to be performed under energized conditions. Glass cap and pin insulation was replaced with silicone rubber composite insulators (NCI’s) with increased creepage and superior performance under polluted conditions. Live line work safety clearance (MAD) was calculated to be 4250 mm at 533 kV DC, using a 1.8 p.u. overvoltage at an altitude of 1500 m, in accordance with IEC 61472 [6]. This includes an ergonomic distance of 0.5 m which is applied in Eskom. In an effort to compare this with international best practices, Eskom found that information related to HVDC live work clearances was rather limited (Table 5.4). On site, however, Eskom found that because of physical tower dimensions and coupling length of new composite insulators the required clearance could not be achieved. With multiple bridges however Eskom could reduce the voltage by 25% to 400 kV which then results in a calculated clearance (MAD) requirement of 3200 mm which could easily be achieved. A table was compiled stipulating the various voltage possible levels and minimum required healthy disks to allow safe bare hand live line work (Table 5.5).

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Fig. 5.24 Helicopter based aerial washing under live conditions

Table 5.4 Clearance (MAD) calculation parameters

Live line work on DC line Overvoltage factor

1.8 p.u

Altitude

1500 m

Temperature (T)

40 °C

Relative air density (σ)

0.781

Gap factor (k)

1.2

Stat. withstand voltage U (10%)

1055.34

CFO

1128

Distance at sea level, d

3.01 m

Go

–

T

0.64

U/U (0)

0.87

Ua

979.11

ka

0.87

Distance at 1500 m Da

3.74 m

Minimum approach distance

4.24 m

Re-insulation was performed at 400 kV DC using helicopter based underslung aerial live line work technique. Eskom employed basic live work principles and tools relevant to AC with the above clearance (MAD) values (Figs. 5.25 and 5.26).

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Table 5.5 Results from research report, Cahora Bassa clearance and live line upgradeability, RES/RR/10/31769, dated 27 March 2010 Line voltage (kV)

% of 533 kV Maximum DC nominal line voltage voltage (%) (kV)

Electrical component (m)

Ergonomic Live work distance (m) safe approach distance (m)

Minimum number of healthy disks for safe live work

600

113

618

4.6

0.5

5.1

N/A—No live work

533

100

549

3.9

0.5

4.24

N/A—No live work

400

75

412

2.7

0.5

3.2

21

267

50

275

1.6

0.5

2.1

17

133

25

137

0.75

0.5

1.25

8

Fig. 5.25 Suspension insulator replacement using helicopter underslung technique and hydraulic lifting machine

Research Internationally there are various aspects related to HVDC and live line work that are being researched. Eskom also has research projects related to HVDC in general, and on live line work, but to date nothing has been conclusive. While much is said about space charges there is no definite information related to its effect on live line work practices, techniques, and tools.

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Fig. 5.26 Strain insulator replacement using cradle and thread and trunnions

References 1. IEC Standard 60050-651. International Electrotechnical vocabulary—part 651: live working (2014). www.webstore.iec.ch 2. EPRI Live Working Reference Book, 2nd edn. EPRI, Palo Alto, CA, p. 1024479 (2011) 3. CIGRE Technical Brochure 561. Live Work—A Management Perspective. JWG B2/B3.27. Paris (2013). www.e-cigre.org 4. EPRI Report 3002007637. Space Charge and DC Bias Effects on HVDC Live-Line Working Tool. Palo Alto, California. www.epri.com 5. IEEE Std. 516-2009. Guide for maintenance methods on energized overhead power lines. New York NY 10016–5997, USA 6. IEC 61472. Live working—minimum approach distances for A.C. systems in the voltage range 725 kV to 800 kV—a method of calculation (2013). www.webstore.iec.ch 7. Hu, Y., et al.: Key technology research and application of live working technology on EHV/ UHV transmission lines in China. In: International Conference on Power System Technology. Chengdu, pp. 2299–2309 8. Occupational Safety and Health Administration (OHSA) Standard 1910.269 9. CIGRE Technical Brochure 865. Inspection and Testing of Tools, Equipment and Training for Live-Line Work on Overhead Lines. WG B2.64, Paris (2022). www.e-cigre.org 10. CIGRE Technical Brochure 731. The Use of Robotics in Assessment and Maintenance of OHL’s. WG B2.52, Paris (2018). www.e-cigre.org 11. EPRI High Voltage Direct Current (HVDC) Transmission Reference Book, 2018 edn. Report 3002012867. Palo Alto, California. www.epri.com

6

Construction Techniques

Contents 6.1 6.2

General Considerations for Compact Line Construction . . . . . . . . . . . . . . . . . . . . . . . . . . . 131 Interface Between Underground Cable and Overhead Power Line . . . . . . . . . . . . . . . . . . 136

Abstract

In general, it can be stated that there are no specific differences between the construction of conventional lines and that of compact lines. The same general techniques are used for stringing, erecting supports, or completing the civil works, irrespective of the pole spacing. The differences can be found in the particular design of the line components (tower/pole, bundle configuration, cross-arms, fittings…). It is thus suggested that each line construction be dealt with on a case-by-case basis, as is normally the case for a conventionally spaced line design.

6.1

General Considerations for Compact Line Construction

Depending on the particular line design and components used in an overhead power line, the construction processes may be different. However, the following general considerations can be outlined, considering that these considerations may be applicable to many compact line designs, although are not exclusive of compact lines and can be also applicable to other line designs. This chapter has taken information from the CIGRE Green Book on Overhead Lines [1].

© Springer Nature Switzerland AG 2024 R. Stephen and J. Iglesias (eds.), Compact Overhead Line Design, Compact Studies, https://doi.org/10.1007/978-3-031-44524-8_6

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Right of Way clearing and site access Transmission line Right of Way may require removal of trees and shrubs to allow for construction activities. In many cases, vegetation is allowed within a transmission line Right of Way providing it is controlled and does not lead to operational problems (i.e. tree contacts with an energized conductor leading to line outages). Various techniques are used in the Right of Way clearing depending on site specific requirements and license conditions. They range from the use of shear blades to remove most of the vegetation to the use of chain saws to remove individual trees. In some cases, vegetation clearing is done at the structure locations only. In other cases, no vegetation clearing is allowed at all and so-called “tree canopy” towers are used with the conductor hanging above the treetop. For compact lines the Right of Way is often narrower than that for conventional lines. Less vegetation removal may be required. The voltage gradient on the conductors may be higher than more conventional lines which makes it more imperative that vegetation is not in close proximity to the conductors. Tower assembling and erection Compact lines have much smaller distances between phases or poles than conventional designs. This can often lead to smaller and/or lighter supports, which influences the assembling and erecting methods, as well as the civil works required. In general, lighter machinery and easier assembling operations and methods could be expected, although it is very influenced by the different types of towers and designs, as mentioned below. Another aspect that can be mentioned is the potential possibility to increase automatization of the assembling and erecting processes when using smaller towers or supports. If the size of the towers is small enough, the techniques could be similar to those used in lower voltages or railway catenaries, for example. Towers or supports for compact lines can include poles, lattice, and variations of these. The three phases (AC) may be surrounded by a lattice framework. In the case of cross rope towers the overall footprint may be smaller than with conventional towers. If the purpose of the compact line is to occupy a narrow servitude perhaps along a roadway, the access to the line route may be less onerous than a conventional line traversing a more rural or remote location. More sophisticated lifting equipment may be required to ensure limited interference with roads, etc. Composite post or braced insulators may be used in compact lines more frequently than conventional lines where “I” strings of glass porcelain discs may be used. These post insulator assemblies may be installed prior to the tower been erected or moved into place. Additional care needs to be taken to avoid damage to the sheds in this case (Fig. 6.1). The erection methods for compact towers are similar to conventional towers or structures. The considerations and methods described in [1], Chapter 15, can be applied.

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Fig. 6.1 Example of lifting a pole with braced-insulators

Stringing Due to the smaller phase to phase or pole to pole distances, the design of compact towers may present some key aspects that can affect the stringing processes. For instance, the insulation solution is of great importance during the stringing and terminating. In particular, the methods and practices needed for insulated cross-arm and other special assemblies described in Chap. 4 may be of great importance when constructing a compact line to avoid damages or accidents. Also, some particular tower designs like cross-rope or guyed towers present very different methods compared with self-supported towers. Additionally, some compact designs may have smaller spans than those used in conventional designs. Therefore, the stringing methods and machinery could be adapted to this fact, optimizing the process, but considering that the bundling configuration and type of conductor can be even more important than the span length. As described in [1], there are two main methods of stringing currently employed. These are tension or slack stringing. In the slack stringing method, “the conductor reel(s) are placed on reel stands or “jack stands” at the beginning of the stringing location. The conductor is unreeled from the shipping reel and dragged along the ground by means of a vehicle or pulling device. When the conductor is dragged past a supporting structure, pulling is stopped and the conductor is placed in stringing blocks attached to the structure. The conductor is then reattached to the pulling equipment and the pull is continued

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to the next structure. This method requires heavy traffic in the Right of Way and is not recommended for “transmission applications”. The conductor is kept off the ground with wood or other supports. With this method the conductor is often scratched or marked. For compact lines, the voltage stress on the conductors is generally higher than for conventional lines. This means that any scratch or nick on the conductor surface will result in corona and audible noise. As compact lines are often constructed in densely populated areas, any audible noise will have dire consequences. For compact lines, this method should therefore not be used for any voltage above the medium voltage ranges. A tension stringing method is the preferred method for installing conductors on compact lines. A general description of the method is outlined below, taken from [1]. Using this tension stringing method, the conductor reel is mounted on a payoff that can apply braking force to the reel to maintain tension on the conductor. The conductor is then strung (or “reeved”) through a multi-groove bullwheel tensioner so that the conductor is under tension during pulling and is not allowed to contact the ground (see Fig. 6.2). It is important to coordinate the bullwheel speed with the puller speed to prevent excessive sagging or dynamic loading (jerking) of the conductor during the pull. In a typical tension stringing operation, blocks (also known as “travelers” or “sheaves”) are attached to each structure or the end of an insulator string. A pilot line is pulled through the blocks and used to pull in a heavier pulling line, which is then used to pull the conductor through the blocks. The tension in the conductor is controlled by coordinating the tension puller at the pulling end and the bullwheel tensioner at the conductor payout end of the installation. This installation method

Fig. 6.2 Trailer mounted payoffs and a truck mounted bullwheel for tension stringing (courtesy of Southwire Co.) [1]

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keeps the conductor off the ground, minimizing the possibility of surface damage and limiting problems at crossings as well as possible corona issues. For transmission voltages, more than one conductor per phase may often be used. This is for impedance and corona considerations. The bundles may contain 2, 3, 4 or 6 conductors per phase. Bundles greater than 6 conductors per phase are not common but can be present especially in China and Japan. For compact lines, bundles are likely to be more prevalent to reduce the surface gradient on the conductors. When stringing the bundles, it is necessary to ensure “matched” sets are used. These are batches of conductors that are manufactured with a single steel core for every matched pair as well as being produced from the strander. Should this not be done, the bundle tends to tilt as each conductor in the bundle exhibits different mechanical properties. Insulators For compact lines, composite posts or long rods are normally the preferred type of insulator that is used. These insulators need to be handled with extreme care as damage to the insulator is possible on-site during construction. The damage, such as a damaged core or torn sheds close to the insulator rod, cannot be readily detected. Damaged composite insulators may separate and drop the conductor bundle causing a major outage. The following text is adapted from [1] and revises the methods and practises to be followed when installing composite insulators. The CIGRE Technical Brochure 184 [2] provides a full overview of composite insulator handling techniques. Insulators should be delivered to the construction site in wooden crates protecting them from damage during transportation and handling. At delivery, the crates must be thoroughly checked for any damage. If cracks, dents, or other damage to the crate are found, each insulator should be examined for damage. Any unit with exposed core or damaged sealing of the triple point should be immediately rejected and replaced. Crates containing insulators should be stored above the ground in a dry and covered area. Lids should remain closed to prevent entrance of rodents and to protect insulators against weather elements. Insulators should be delivered to a job site in their original packaging. Direct contact with the ground must be avoided to ensure that clean units without any mechanical damages are installed on the transmission line. A good solution to protect insulators after removing them from crates is application of a wrap-on shield. The use of a wrap-on shield helps to prevent the insulator from damage during installation or tower painting. The wrap-on must be set up to allow the air flow, so that it keeps the insulator from getting moldy. In certain areas, birds may eat or damage the silicon sheds. It is necessary then to keep the protective covers on the conductors until the line is to be energised (Fig. 6.3). When installing the insulators, lifting ropes should be attached to the earthend insulator metal fitting only. Ropes should not have contact with the silicon housing of composite insulators. When installing, insulators must not be subjected

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Fig. 6.3 Post insulator damaged by birds (courtesy of Powerlink, Australia)

to bending or torsional loads. It is forbidden to walk, sit or climb on the insulators and their corona rings. During installation special ladders or temporary bridges must be used. Ladders, tools, blocks and other equipment, should be kept away from the housing of an insulator string to avoid mechanical damage. Insulators damaged during hardware assembly should always be replaced and removed from the site. Other considerations Compact lines may have to be installed in very restricted Right of Ways (like roadside, railway-side or shared corridors). This may require the use of specialized cranes or other lifting devices and machinery yhat can avoid limitations in the accessing. The reduced distances in compact lines as well as the important insulation requirements may encourage the use of new materials and components. It is considered that certain materials or components, like, for example, fiber reinforced polymers (FRP) or new component materials may be of special interest in the development of compact line configurations [3]. One important difference may occur with the potentially more frequent use of underground cable portions in compact line designs. The cable to line interface is therefore an important consideration in the overall design of the system, as explained below.

6.2

Interface Between Underground Cable and Overhead Power Line

Compact overhead power line sections will commonly interface with underground cable sections given that both arrangements are typically applied in congested corridors and/or urban environments. The transition from an overhead power line arrangement to an underground line arrangement requires a transition site or tower.

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Fig. 6.4 Example of underground cable to overhead power line interface structure

In general, these transitions include a structure that supports the bare overhead conductors and facilitates connection to the underground cables with use of cable terminations. These locations regularly include surge arresters to protect the underground cables. For lower voltages, it is possible for all of the necessary components to be located on a single tower often referred to as transition, riser or termination structure as shown in the following figures (Figs. 6.4 and 6.5). For higher voltages, approximately greater than 200 kV, the size of the equipment and the number of cables per phase will typically require a larger site contained within a fence. These transition sites may include other equipment commonly found in switchyards and substations (Fig. 6.6). The presence of an underground section within a transmission line segment will influence the overall line capacity, impedance, and system transients. Protection considerations will also have to be considered as it is not good practice in general to auto-reclose onto a fault in a cable section. The protection needs to determine the location of the fault and operate accordingly.

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Fig. 6.5 Example of underground cable to overhead power line interface station

Fig. 6.6 Example of transition site for underground cable to overhead power line interface

References 1. CIGRE Green Book. Overhead Lines. ISSN 2367-2625, ISSN 2367-2633 (electronic). Springer (2017). www.e-cigre.org 2. CIGRE Technical Brochure 184. Composite Insulator Handling Guide. WG B2.03, Paris (2001). www.e-cigre.org 3. CIGRE Technical Brochure 818. Transmission Line Structures with Fiber Reinforced Polymer (FRP) Composite. WG B2.61, Paris (2001). www.e-cigre.org

7

Influence of Compaction on the Electrical Design

Contents 7.1 7.2 7.3 7.4 7.5

7.6

7.7

Reference Cases . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Insulation Co-ordination . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Geometries to Be Considered . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . AC Line Constants (R, X, L, C) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Corona Effects for AC Lines . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 7.5.1 Conductor Surface Gradient . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 7.5.2 Radio Interference . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 7.5.3 Audible Noise . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 7.5.4 Electric Field . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 7.5.5 Magnetic Field . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 7.5.6 Right of Way Limitation Based on Corona Criteria . . . . . . . . . . . . . . . . . . . . . . . . Corona Effects for DC Lines . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 7.6.1 Conductor Surface Gradient . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 7.6.2 Radio Interference . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 7.6.3 Audible Noise . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 7.6.4 Electric Field and Ion Current Density . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 7.6.5 Right of Way Limitation Based on Corona Criteria . . . . . . . . . . . . . . . . . . . . . . . . Electrical Line Design Criteria Adopted in Different Countries . . . . . . . . . . . . . . . . . . . . 7.7.1 Over-Voltage Values Used . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 7.7.2 Insulation Co-ordination Values Used . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 7.7.3 Corona Effects . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 7.7.4 Fields . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .

140 140 141 144 145 145 147 149 150 152 152 154 155 158 159 161 164 166 166 166 166 166

Abstract

The electrical parameters are subject to the line configuration. This chapter analyses different tower configurations for AC and DC line and determines the electrical parameters for each configuration. The sensitivity of the phase and pole configurations in relation to the electrical parameters is described. In addition the various standards employed in the world relating to electrical values and limits are described. The objective of this section is to get a measure or quantification of the influence of compaction (i.e. the reduction of horizontal © Springer Nature Switzerland AG 2024 R. Stephen and J. Iglesias (eds.), Compact Overhead Line Design, Compact Studies, https://doi.org/10.1007/978-3-031-44524-8_7

139

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R. Stephen and J. Iglesias

and/or vertical distances) on the line electrical design. The sensitivity to various parameters is evaluated to quantify the influence of the parameter change. Different configurations and geometries can be analysed to fulfil the regulatory requirements or limits related to the electrical parameters. A summary of these limits in several countries around the world is also included for information.

7.1

Reference Cases

As reference, a base case for both HVAC and HVDC lines are considered with the characteristics shown in Figs. 7.1 and 7.2.

7.2

Insulation Co-ordination

Insulation co-ordination aims at designing the clearances and at defining the type of insulation to be used on the overhead power line, [1–3], see also Chap. 3. The type and length of insulation (insulator type and number of insulators in the string) is selected based on the maximum voltage withstand and on the assumption of a certain pollution level. The main electrical clearances, phase, or pole-to-ground (P-G) and phase-to-phase or pole-to-pole (P-P), to be determined are conductor-to-tower or objects (lateral), conductor-to-ground or objects (at the ground). They are calculated for operating voltage and switching surge overvoltage withstand. The clearance to objects at the edge of Right of Way shall be verified in

Guyed Cross-Rope flat configuration V= 500 kV (Vmax = 550kV) Current Capability: 1700 A (@ 90C) Bundle: 4 x 954MCM (~483mm2) Cond. diameter 29.61 mm (Rail) Sub-conductor spacing: 45.7 cm Phase spacing: 5.5 m Min. distance to ground: 12 m Conductor sag: 18.0 m Groundwires: EHS 3/8” Groundwires spacing 24.8 m Groundwire height: 40 m Groundwire sag: 12.0 m Soil resistivity 500 Ω m

Fig. 7.1 Base case for HVAC line

7 Influence of Compaction on the Electrical Design

141

Guyed support flat configuration V=500 kV; Current Capability=1470 A (@ 90C) Power Economic=1300 MW Bundle: 3 x 1590 MCM Cond. Diameter: 38.22 mm (Lapwing) Bundle Spacing: 45.7 cm; Pole Spacing 13.0 m Pole Height (min.): 12.5 m Pole Sag: 22.5 m Av. Span: 450 m ROW=67 m Groundwire: 3/8” EHS; Groundwire Sag: 16 m Insulator string: 30 anti-fog discs Pitch=165 mm Soil resistivity 500 Ω m

Fig. 7.2 Base case for HVDC line

Table 7.1 AC conductor clearances to the tower (horizontal distances) Insulator string

Power frequency

Switching surge

Insertion of V Cond. string (m) clearance (m)

Clearance (m)

Swing (m)

Clearance (m)

Swing (m)

V

1.2

0

1.93

0

3.25

3.25

I

1.2

3.9

1.93

1.42

0

5.10

the condition of conductor swing due to wind to prevent flashovers and the touch to objects such as trees. For AC lines, the Table 7.1 shows the minimum values used to create alternative geometries for conductor-to-tower clearances in a 500 kV line. For phase-to-phase distance the minimum value considered is 5.5 m. For DC lines, the Table 7.2 is considered. The minimum pole spacing required is the sum of P-P clearances and two times the bundle radius R. When using I-string the conductor swing must be considered.

7.3

Geometries to Be Considered

The next step is to determine the Ph–Ph or P-P distances for the alternative configurations.

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Table 7.2 DC pole spacing for different tower types Voltage Minimum clearance required for: Pole spacing tower type (m) (kV) (m)

± 500

Operating voltage P-G air gap

Operating Switching a voltage surge P-G (I-string) P-P gap air gap with insulator

2.4

10.4

3.1

b

c

12.5–14.0 9.0–11.0 7.5–11.0

d

a (V-string)

> 3.7 9.3

Fig. 7.3 Phase spacing and arrangements to be evaluated (AC line, single circuit)

For AC, the following alternatives are adopted (see Fig. 7.3). • Horizontal configuration of phases (T1). Considering tower leg with 2 m, bundle spacing of 0.47 m and V string the Ph–Ph distance becomes ~ 9 m • Horizontal configuration of phases (T2). In this case the Ph–Ph distance is determined by switching surge Ph–Ph withstand, therefore ~ 5.5 m • Middle apex up triangle (T3). Considering the tower width of 2.5 m at lower phase height, a bundle spacing 0.47 m and a V string, it results in a Ph–Ph distance of 9.5 m between the lower phases. The distances from lower to top phases may be estimated to be around 9.5 m • Middle vertice (apex) up triangle (T4 andT5). The Ph–Ph distances are limited by Ph–Ph switching surge withstands at 5.5 m. In the T4 case the length of the Ph–Ph insulation string will be determinant plus bundle spacing leading to Ph = Ph distance of 9 m. For T5 the Ph–Ph distances can be 5.5 m and the phases can be provided with I string. • Y/Δ configuration (T6, T7). In these cases the string length will determine the Ph–Ph distances to be around 8.5 and 9 m unless polymeric insulators are used instead of standard glass cap and pin insulators.

7 Influence of Compaction on the Electrical Design

143

• E/W triangle (T8). Considering tower width of 2 m; bundle spacing of 0.47 and switching surge clearances, it results in Ph–Ph distances of 9.0 m for upper/ lower phases and 10.5 m for left/right phases. Additionally, different Double-Circuit tower arrangements (D1–D7) are shown below (max. operating voltage of 420 kV, bundle spacing 400 mm). Towers D1–D3 vertical-design and D5–D7 Danube-design (Fig. 7.4). For DC lines, based on the above range of possibilities, the following arrangements and pole spacing will be considered in the corona and field evaluation (see Fig. 7.5; Table 7.3).

Fig. 7.4 Phase spacing and arrangements to be evaluated (AC line, double circuit)

Fig. 7.5 Pole spacing and arrangements to be evaluated (DC line)

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Table 7.3 Alternatives to be evaluated for DC line

Alternative

Configuration (tower, chain)

Pole spacing (m)

1 (base)

a (II)

13.1

2

a (VV)

3

b (VHV)

4

c (VV)

7.7

5

d vertical (VV)

3.7

6

(Same as 5)

4.5

9.3 11.0

The same analysis can be performed for a double circuit line, but it has to be noted that different combinations of the positive/negative pole position in the tower must be considered.

7.4

AC Line Constants (R, X, L, C)

The line parameters are calculated assuming full transposition and average height of the conductors. The equations are below. ( X L = 2(2π f ) Ln C=

) Ω GMD 10−4 G M Rz km

μF 1 ) ( )) ( ( Dii Dik km 17.976 Ln G M Rc − Ln G M D √ GMR = R

n

Fnr R

(7.1) (7.2)

(7.3)

F = 1 for GMRc and ~ 0.8 for GMRz. R=

a ( ) 2 sin πn

(7.4)

where a n

is the bundle spacing is the number of subconductors in a bundle.

GMD =

√ 3

d12 d13 d32

where d ij

is the distance between conductors i, j

(7.5)

7 Influence of Compaction on the Electrical Design

145

Table 7.4 Parameters of the alternative line configurations (AC line, single circuit) Configuration

GMD (m)

XL (Ω/km)

C (μF/km)

Zc (Ω)

SIL (MW)

T1

11.34

0.303

0.01416

238.4

1048.9

T2 (basic case)

6.93

0.266

0.01604

209.8

1191.5

T3

9.50

0.290

0.01471

228.7

1093.3

T5

5.50

0.249

0.01712

196.3

1273.3

T6/T7

9.50

0.290

0.01469

228.8

1092.6

T8

9.97

0.294

0.01451

231.7

1079.0

Note R = 0.0155 Ω/km; GMRc = 0.211 m and GMRz = 0.203 m; the same for all alternatives

Dii Dik

is the distance conductor to its image is the distance conductor to the image of the other.

Dii = Dik =

√ 3 √ 3

D11 D22 D33

(7.6)

D12 D23 D31

(7.7)

Being f = 60 Hz. SIL is the value with V = 500 kV. The results are in Table 7.4. The lower the GMD (compaction) the lower the XL and Zc but the higher C and SIL. Higher SIL are also obtained with the same GMD but changing GMR with change in bundle spacing (bundle expansion). SIL affects stability and reactive compensation. The same effect of geometry change can be obtained by proper series and shunt reactive compensation with small change in reactive power cost.

7.5

Corona Effects for AC Lines

Corona effect in the HVAC line lead to radio interference, TV interference and audible noise. The impact of the corona effect is dictated by the maximum conductor surface gradient (Emax) calculated with maximum voltage (550 kV) and its ratio to the Peek gradient. Therefore, to analyse the impact of compaction it can be done first by measuring the variation on Gmx.

7.5.1 Conductor Surface Gradient The simplified process to evaluate the maximum conductor surface gradient in HVAC lines are reproduced in [2] and consists of the following steps.

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Calculation of the charge Q = H − 1 V, being H the Maxwell coefficient and V the voltage: Gmx =

Q r, R n εo

( ) Q (n − 1)r 1+ r (2π εo)n R

(7.8)

is the charge (C/m) conductor and bundle radius (cm) is number of sub conductor is dielectric constant (F/m).

The sensitivity related to the number of subconductors (phase configurations with almost same total Al area), and to bundle spacing is shown in Table 7.5. The values in Table 7.5 are also shown in Figs. 7.6 and 7.7. The difference of Gmx related to tower configuration is shown in Table 7.6. The central phase has higher gradient, and the gradients are proportional to the GMD. Table 7.5 Sensitivity of Gmx to number and spacing of subconductor N

#

MCM/mm2

a (cm)

d (cm)

Central Ph kV/cm

External Ph kV/cm

1 (basic)

4

954/483

45.7

2.961

19.71

17.15

2

3

1272/644

45.7

3.417

20.44

18.01

3

6

636/322

45.7

2.484

18.48

15.72

4

4

954/483

20

2.961

18.93

16.84

5

4

954/483

30

2.961

18.99

16.73

6

4

954/483

70

2.961

21.09

18.09

22

kV/cm

20 18 16

central

14

external

12 10

2

3

4 5 conductor/phase

6

7

Fig. 7.6 Surface Gradient as function of the number of conductor per phase (same total Al section)

7 Influence of Compaction on the Electrical Design

147

22

kV/cm

20 18 16

central

14

external

12 10

0

20

40 60 bundle spacing (cm)

80

Fig. 7.7 Surface Gradient as function of the bundle spacing (same conductor configuration)

Table 7.6 Gmx for the tower alternative configuration (AC line, single circuit)

#

GMD (m)

kV/cm Central

External

T1

11.34

16.99

15.22

T2

6.93

20.44

18.01

T3

9.50

16.62

16.63

T5

5.50

19.69

19.28

T6/T7

9.50

17.24

16.25

T8

9.97

16.78/16.55/16.18

7.5.2 Radio Interference The Radio Interference (RI) values at soil, in a cross section perpendicular to the line, are here calculated using equations from [2] as below, which considers CISPR specification: QP: 9 kHz. For “heavy rain” weather: ( RIhr = −10 + 3.5g + 6d − 33 log

) D dBμ 20

where g D d

is the maximum surface gradient (function of the mean height) (kV/cm) is the radial distance from the phase to the point (m) is the sub conductor diameter (cm).

Valid for: 10 m < D < 60 m, and 1 cm < d < 2.5 cm only.

(9)

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It should be noted that: • From the heavy rain value subtract 24 dBμ to get mean fair weather value; • From the heavy rain value subtract 7 dBμ to get “mean foul weather” value. The equation applies for each phase, and the total RI can be calculated by: ⎛[ ⎞ | 3 |∑ 2⎠ E ki E i = 20 log⎝√

(7.10)

k=1

E k j = 10

R Ik j 20

(7.11)

The values of the noise for the various arrangements (mean fair weather) are shown in Fig. 7.8. The RI noise criterion may consider signal 66 dBμ, Signal-toNoise Ratio SNR = 18 dBμ (interference audible but speech perfectly received), therefore the following alternatives may be used:

Fig. 7.8 Radio Interference mean fair weather for the alternatives (AC line, single circuit)

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149

• mn fair weather noise = 48 dBμ, to match fair weather 50% probability • mean fair weather noise = 48 − 12 = 36 dBμ, to match fair weather 98% probability (lower). • mean fair weather noise = 48 − 17 = 31 dBμ, to match foul weather 50% probability. High compaction may impact the Right of Way width.

7.5.3 Audible Noise Audible noise (wet conductor) values in the soil, cross section perpendicular to the line, are here calculated using equations from [2] as below. For “wet conductor” the average excitation function is (Table 7.7). [ A50 = K 1 + 120 log g + K 2 log n + 55 log d +

q 300

(7.12)

To obtain average value for fair weather subtract 25 dBA from the value in the equation. Range of validity: 230 – 1500 kV, n ≤ 16, 2 ≤ d ≤ 6.5 cm. The audible noise AN level in dBA is: L A = [ A + 54.3 − 11.4 log D

(7.13)

[ A5 = [ A50 + 3.5

(7.14)

The sum of the individual pressure values from all phases results in the total sound pressure at the point. L AT ot = 10 log

3 ∑

10

L Ai 10

(7.15)

i=1

The audible noise limits depend on each country regulation, and a typical limit value could be 42 dBA which corresponds to suburban living room noise. The values of the noise for the various arrangements are shown in Fig. 7.9. Also, the noise design criteria levels are indicated. Table 7.7 Value of K versus n

K1

K2

n 120

70

T3

70

Not an issue

T5

> 120

90

T6–T7

65

Not an issue

T8

75

Not an issue

Values in meter

temperature, etc., lead to the value of 60 m for the ROW (corresponding to swing angle of 45°, 50 years return period wind, 35 m of maximum sag for a 600 m span length and clearance for operating voltage of 1.2 m). This means that the insulation coordination is not limiting factor for these cases. Regarding the limits of the electric and magnetic fields, the criteria is based on the reference values recommendations of ICNIRP [4]. The ICNIRP defines two type of exposures: “general public” and “occupational”; the latter applied to people that works in the electrical system ambient, and the former related to all other people not aware of that may be a field effect. Table 7.9 indicates the Occupational and Public exposure limits at 50 and 60 Hz. Table 7.10 indicates the required and calculated levels based on the example.

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Table 7.9 ICNIRP reference values [4] 50 Hz

60 Hz

Units

Occupational Electric field basic restriction: head

100

120

mV/m

Electric field basic restriction: whole body

800

800

mV/m

Magnetic field reference levels

1000

1000

μT

Electric field reference level

10

8.333

kV m−1

Electric field basic restriction: head

20

24

mV/m

Electric field basic restriction: whole body

400

400

mV/m

Magnetic field reference levels

200

200

μT

Electric field reference level

5

4.167

kV m−1

General public

Table 7.10 Required and legal limits for electric and magnetic fields Electric field

Magnetic field

Occupational, 50 Hz Basic occupational restriction in head

100 mV/m

–

Basic occupational restriction in whole body

800 mV/m

–

ICNIRP reference level

10 kV/m

1 mT

Field actually achieved

24.2 kV/m

3.03 mT

General public, 50 Hz Basic restriction in head

20 mV/m

–

Basic restriction in whole body

400 mV/m

–

ICNIRP reference level

5 kV/m

200 μT

Field actually achieved

9.9 kV/m

606 μT

Calculation limits

The above calculation indicates that the example will not meet magnetic and electric field constraints at 50 and 60 Hz. The designer will have to rework the configuration (phase spacing, bundle configuration, height above ground) to determine a compliant design.

7.6

Corona Effects for DC Lines

Corona effect in the HVDC line may lead to radio interference (RI), TV interference (TVI), and audible noise (AN). The corona effect is dictated by the maximum conductor surface gradient (E m ) and it’s ratio to the Peek gradient. Therefore, the impact of compaction can be firstly seen by measuring the variation on E m .

7 Influence of Compaction on the Electrical Design

155

7.6.1 Conductor Surface Gradient The simplified equations to evaluate the maximum conductor surface gradient in HVDC lines are reproduced in [2, 3]. For a bipolar HVDC transmission line with a single conductor, the average and maximum conductor surface gradients E a and E m , respectively, in kV/cm, are given as: Em = Ea =

V r · ln r

√( 2H) 2 2H S

(7.16) +1

where V r H S

voltage applied (actually ± V ) to the conductors of the line, kV conductor radius, cm conductor height, cm pole spacing, cm.

When bundled conductors are used, the electric field around the sub-conductors of the bundle is distributed non-uniformly, with maximum and minimum gradients occurring at diametrically opposite points and the average gdient at a point in between. The degree of non-uniformity increases as the number of sub-conductors as well as the ratio of the sub-conductor radius to the bundle radius increase. Using the Markt and Mengele’s method, the average and maximum bundle gradients of a bipolar HVDC line, with n-conductor bundles on each pole, are given as [2, 3]. Ea =

V n · r · ln

√(2H ) req

[

2H S

E m = E a 1 + (n − 1)

(7.17) 2

+1

r] R

(7.18)

For greater accuracy of conductor surface gradient and, to calculate surface gradient on groundwires, calculations can be performed based on theory of images using capacitance matrix and potential matrix. where n r R req

number of sub-conductor in the bundle sub-conductor radius, cm bundle radius, cm equivalent bundle radius, cm

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R. Stephen and J. Iglesias

R=

a

a ( π )m 2sin N

(7.19)

distance between adjacent subconductors, cm.

req = R ·

[ n · r ]1/n R

(7.20)

The following aspects will be considered in the evaluation of maximum surface conductor gradient: • • • • •

conductor diameter pole spacing bundle spacing conductor height horizontal/vertical configuration.

Variations will be compared with the base case mentioned above. Figure 7.14 shows the variation due to number of conductors per pole. Note that for the same total cross section the surface gradients are very similar. In Fig. 7.15 the effect of bundle spacing is shown. Note that there are minimum points in the curves. The maximum conductor surface gradient varies with pole spacing and conductor height and therefore with tower/conductor arrangement. In the Fig. 7.16 this variation is shown for several pole spacing and considering two height values, the minimum height, and the average height (minimum height plus 1/3 of the sag).

Fig. 7.14 Gradient as function of the number of conductors per pole

7 Influence of Compaction on the Electrical Design

157

Fig. 7.15 Gradient as function of the bundle spacing (basic case)

35

Peek grad 29.66 kV/cm

30 25 20

pole spacing (m)

15

minimum height

10

average height

5 0 1

2

3

4

5

5a

alternative

Fig. 7.16 Conductor surface gradient as a function of pole-spacing and conductor height parallel to ground (minimum and average)

Notes: 1. For cases 5 and 5a the gradient refers to the lower conductor. 2. Peek gradient is 29.67 kV/cm, with m = 0.82; air density 0.95. As the pole spacing reduces in size, the conductor surface gradient increases. There is no difference for vertical or horizontal configuration with the same pole spacing (7.7 m of pole spacing was tested with both arrangements).

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Using the average value for the height of conductor instead of minimum height in the calculation, lower values of gradient are obtained (22.9 kV/cm in the former and 23.3 kV/cm in the latter for case 1).

7.6.2 Radio Interference Based on data obtained on experiments as well as operating lines, a simple empirical formula has been developed [2, 3] for predicting the average fair weather RI level for bipolar HVDC overhead power lines: ( ) ( ) d g + 40 log R I = 51.7 + 86 log g0 d0 { [ ]2 } 19.9 q + 40 log + 10 1 − log(10 · f ) + D 300

(7.21)

where RI g d f D q

radio interference level measured at a distance D from the positive pole dB above 1 μV/m maximum bundle gradient, kV/cm conductor diameter, cm frequency, MHz radial distance from positive pole, m altitude, m.

The reference values are g0 = 25.6 kV/cm and d0 = 4.62 cm. Adequate statistical information is not presently available to determine the difference in the RI level between the average and maximum fair-weather values or between the fair and foul weather values. However, based on the results of some long-term studies [the maximum fairweather RI may be obtained by adding 6 dB; and the average foul weather RI may be obtained by subtracting 5 dB from the average fair weather value. Design criteria for RI from overhead power lines are generally based on signal to noise ratios (SNR) for acceptable AM radio reception. Studies carried out on corona-generated RI from AC and DC overhead power lines indicate that the SNRs for acceptable radio reception are: • Background not detectable: SNR > 30 dB • Background detectable: 20 dB • Background evident: 8 dB. Minimum radio station signal requirement in Brazil is 66 dB for cities with population from 2500 to 10,000 inhabitants. Similar condition probably applies to other countries and is used here as part of the criteria.

7 Influence of Compaction on the Electrical Design

159

65 dBμ 60 55

case 6 pos lower

50

case 5 pos lower

45

case 4

40

case 3

35 30

case 2

25

case 1

20 0

20 40 60 distance to center (m)

80

criteria

Fig. 7.17 Radio Interference (positive conductor only)

At present, there are no established design criteria for RI from DC overhead power lines; so the tentative guidelines are for limiting the RI at the edge of the Right of Way to (66 – 20) = 46 dB or to keep a reception quality (b) at the reception. The equation for calculating noise above gives the average fair-weather noise. For more stringent criteria, the noise shall be below 46 – 4 = 42 dB for 90% probability of not being exceeded, meaning that in 10% of the time the reception will be classified as between the criteria (b) and (c) above. The reference frequency is considered in [3] as 1 MHz, and the line is at an average altitude of 600 m. The values of the noise for the various arrangements are shown on Fig. 7.17 (f = 1 MHz, average height and q = 600 m). Notes: • In the alternatives 5 and 6 the positive conductor is the lower. • The contribution of the negative pole has to be added and has greater influence in the vertical configuration and smaller pole spacing.

7.6.3 Audible Noise Based on measurements made on experimental as well as operating DC lines and the general characteristics of corona-generated AN, an empirical formula has been developed for the mean fair weather AN, in dBA, from a DC line as:

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R. Stephen and J. Iglesias

AN = AN0 + 86 log(g) + k log(n) + 40 log(d) − 11.4 log(R) +

q 300

(7.22)

where g n d R

average maximum bundle gradient, kV/cm number of sub-conductors conductor diameter, cm radial distance from the positive conductor to the point of observation

The empirical constants k and AN0 are given as: k = 25.6 k=0 AN0 = −100.62 AN0 = −93.4

for n for n for n for n

>2 = 1 or 2 >2 = 1 or 2

The values of the noise for the various arrangements (as per Table 7.3) are shown on Fig. 7.18. Notes: • In the alternative 5 the positive conductor is the lower. • The contribution of the negative pole must be added and has greater influence in the vertical configuration and smaller pole spacing.

55 dBA # 6 pos lower

50

case 5 case 4

45

case 2 40

case 1 criteria

35

# 6 pos higher case 3

30 0

20

40 dist center (m)

Fig. 7.18 Audible noise (positive conductor only)

60

80

7 Influence of Compaction on the Electrical Design

161

The maximum fair weather AN (probability 10% of not being exceeded [5].) is calculated by adding 5 dBA to the mean fair-weather value obtained above, while the mean AN during rain is calculated by subtracting 6 dBA from the mean fairweather AN. As in the case of RI, there are presently no regulations for AN from HVDC overhead power lines. The Environmental Protection Agency (EPA) in the US recommends that the day-night average sound level L dn [3] be limited to 55 dBA outdoors. The level L dn is defined as: L dn

( [ ]) Ld L n +10 1 15 × 10 10 + 9 × 10 10 = 10 log 24

(7.23)

where L d and L n are the day and night-time sound levels, respectively. However, since the highest level of AN from DC lines occurs in fair weather, it may be prudent to limit the L dn (10%) of AN from HVDC overhead power lines to 55 dBA, and this correspond to 50 dBA for L dn (50%). Reference [5] indates that the night and the all-time distribution are close together by 1.5 dBA. Therefore assuming L d = L n = 42–44 dBA, results L dn ~ 50 dBA. As a conclusion, the AN calculated by the equation above (average value) shall be limited to ~ 42 dBA at the edge of the Right of Way. The consideration of the conductor height may have an impact in the Audible Noise determination, and thus the potential limitation of the ROW due to noise. To calculate the capacitance, the conductor is supposed to be parallel to the soil, but it is a catenary. To consider this geometry there are two possibilities to carry out the calculation: considering the mid-span height (max. sag) or considering the equivalent height (mid-span plus 1/3 of the sag). Therefore, two values of gradient are obtained. Additionally, The RI and AN for HVDC lines are mainly due to corona in the positive pole. The contribution of negative pole is minor. Therefore, the noise in the negative pole side of the line is smaller. One can choose ROW shorter in the negative side of the line than in the positive. This may produce important savings and benefits during negotiation or construction provided that this phenomenon governs the ROW width choice.

7.6.4 Electric Field and Ion Current Density The static electric fields produced by DC lines do not produce significant electric fields or currents inside the body to cause biological effects, consequently, no limits have been recommended by ICNIRP [4]. In absence of other concerns, the remaining effects of DC electric fields are the ions produced by corona, and their charging effects on body hair and skin, as well as the resulting annoying micro shocks occurring when touching charged or grounded metallic objects under the line.

162

R. Stephen and J. Iglesias

To calculate HVDC electric field there are three methods: • Solution of Maxwell equations (differential) by simplifications and direct integration (with software); • By finite elements. • The so-called saturation method (semi-empirical). Key information for the two analytical method is the onset gradient, value difficult to be established, that depends on season; conductor surface and therefore has a statically behaviour. The semi-empirical method is based on small scale model complemented with test line measurements in high voltage laboratory. There are parameters for all season and values with 50 and 95% probability [5]. To evaluate the electric field on the ground perpendicular to the line at mid span, a software is used to solve Maxwell equations. The electric field and ionic current for alternatives 1, 4 and 6 (as per Table 7.3) are shown in Figs. 7.19 and 7.20. The vertical arrangement has slightly higher values of electric field and similar values of ionic current. Horizontal configurations have similar values for 3.7 or 7.7 m of pole spacing. The calculations were also performed using the saturation method for configuration T1 and T2 (as per Table 7.3), and the results are shown in Figs. 7.21 and 7.22.

100 J (nA/m2 ) 80 60 40 20

case 6

0 -100

-50

-20 0

50

100

-40 -60 -80 -100 distance to center (m) Fig. 7.19 Ion current density for cases 1, 4 and 6, calculated with software

case 4 case 1

7 Influence of Compaction on the Electrical Design

163

40 kV/m

30 20 10

case 1 case 4

0 -60

-40

-20

0

20

40

60

-10

case 6

-20 -30 -40 distance to center (m) Fig. 7.20 Electric field for cases 1, 4 and 6, calculated with software

electric field 40 kV/m 30 20

T1 spring 50%

10 0 -40 -30 -20 -10 0 -10

T2 spring 50% T1 spring 95% 10 20 30 40

T2 spring 95% T1 H humid sum 95%

-20

T2 H humid sum 95%

-30 -40 distance (m) Fig. 7.21 Electric field for cases 1 and 2, calculated with the saturation method

164

R. Stephen and J. Iglesias

ionic current J (nA/m2 )

100 50

0 -40 -30 -20 -10 0 -50

T1 spring 95% 10 20 30 40

-100

T1 humid sum 95% T2 humid sum 95% T1 spring 50%

-150 distance (m) Fig. 7.22 Ionic current density for cases 1 and 2, calculated with the saturation method

So far, there is no agreed criteria for maximum limits, although 40 kV/m and 100 nA/m2 are mentioned [3] for worst meteorological condition (summer with high humidity). As for [5], no concerned biological effect are reported due to DC fields and ion currents except skin/hair movement. Figure 7.23 show the dependence of parameters. From Fig. 7.23 for the state criteria 50% of the people perceive the field, as another 50% does not perceive, it may indicate that the stress is small. For the edge more stringent values may be adopted, like for example 15 kV/m and 50 nA/m2 . In summary, the above criteria are based on perception of the field by humans. Values in Fig. 7.23 indicate that the criteria are matched inside the ROW and with an edge of 25 m.

7.6.5 Right of Way Limitation Based on Corona Criteria Table 7.8 shows the required Right of Way to meet the noise criteria: Radio 46 dBu; Audible 42 dBA. Considering positive pole only; positive in the lower position in the vertical arrangement; gradient and height at mid span. To reduce the Right of Way requirements due to corona effect one may consider a reduction in the bundle spacing. Table 7.11 shows the conductor surface gradients (maximum and average maximum) for the case 5 with two bundle spacing 45.7 and 30 cm, positive pole in the lower position. Remembering that Peek gradient (m = 0.82; air density 0.95) are + 30.93 and − 29.67 kV/cm the reduction to 30 cm does not meet the visual corona criteria, and

7 Influence of Compaction on the Electrical Design

165

Fig. 7.23 Perception of electric field

Table 7.11 Conductor surface gradient for two different bundle spacing (case 5) a

45.7 cm

30 cm

Average E a (kV/cm)

+ 28.31

+ 25.97

− 27.31

− 25.09

[1 + (n − 1) · r /R] Maximum E m (kV/cm)

1.145

1.221

+ 32.41

+ 31.70

− 31.27

− 30.62

do not show improvement in AN (less than 1 dBA) ROW for minimum clearance at the edge and final selection. To fulfil the ROW requirements for insulation coordination, the conditions (wind, sag, temperature) described in [3] are assumed. These conditions lead to the value of 53 m for ROW (corresponding to swing angle of 39°; sag 34.9 m; clearance for operating voltage). Therefore, the final ROW for the cases defined in Table 7.3 will be those of Table 7.8, the bigger value to be adopted (Table 7.12).

166

R. Stephen and J. Iglesias

Table 7.12 ROW for radio interference, audible noise and clearance to edge (m) Case

RI

AN

I clearance

V clearance

1

44

0

66.1

59.5

2

54

0

62.3

55.7

3

50

0

64.0

57.4

4

64

45

60.7

54.1

5

100

> 150

53.0

46.4

6

85

> 150

53.0

46.4

7.7

Electrical Line Design Criteria Adopted in Different Countries

The references [6, 7] include a comparison of the design criteria used in different countries. Those values were obtained from an inquire and are reproduced here below. Note that the values can only be adopted from one country. It is not possible or desirable to take values of one parameter from one country and the value of another parameter from another country as they are interactive.

7.7.1 Over-Voltage Values Used See Tables 7.13 and 7.14.

7.7.2 Insulation Co-ordination Values Used See Tables 7.15 and 7.16.

7.7.3 Corona Effects See Tables 7.17 and 7.18.

7.7.4 Fields See Table 7.19.

–

–

–

–

Energization

Phase-to-ground (pu)

Phase-to-phase (pu) –

Phase-to-phase (pu) –

Fault inception

Load rejection, fault clearing (pu)

–

c

d

–

–

–

Phase-to-ground (pu)

–

Reclosing

b

–

< 2.0

< 2.0

–

–

–

–

2.5 (500 kV) 2.7 (345 kV)

a

–

Switching surge V2%

1.1

1.2

–

Operating voltage/ power frequency overvoltage (pu)

Canada

1.1

Norway

Table 7.13 AC values for over-voltages

1.9 (765 kV)

1.9 (765 kV)

4.6/4.0/3.3

3.2/2.4/1.9

–

3.0 (765 kV)

1.7 (765 kV)

–

–

–

Korea

–

–

–

–

–

2.3

2.6

–

–

1.1

Germany

–

–

–

–

–

–

–

–

–

1.3

Brazil

2.3

1.45

4.65

3.1

–

3.45

2.3

–

–

1.45

France

< 2.0

< 2.0

2.0–4.0

2.0–4.0

–

3.0–4.0

2.0–3.5

–

–

1.05–1.20

USA

2.6 (series caps)

1.9

3.6

2.2

–

3.1

1.9

1.0 (400 kVpk)

1.1

USA (BPA)

–

–

3.12/4.5/5.3

2.0 − 3.3

–

–

–

–

–

1.09/1.05 or /1.1

Japan

7 Influence of Compaction on the Electrical Design 167

NA

< 2.0

Phase-to-phase (pu)

Fault inception

Load rejection, fault clearing (pu)

c

d

NA

–

NA

Reclosing

NA

Phase-to-phase (pu)

Phase-to-ground (pu)

b

–

NA

a

–

Energization

Switching surge V2%

1.2

1.0

Phase-to-ground (pu)

Operating voltage/ power frequency overvoltage (pu)

1.1

Norway

NA

< 2.0

–

–

–

–

–

–

1.6 (500 kV)

1.0

Canada (Manitoba)

Table 7.14 DC values for over-voltages

–

–

–

–

–

–

–

–

–

–

Canata (Ontario)

NA

< 2.0

NA

NA

NA

NA

–

–

1.0

Korea

–

–

–

–

–

1.8

2.0

–

–

1.1

Germany

NA

1.8

NA

NA

–

NA

NA

–

–

1.0

Brasil

–

–

–

–

–

–

–

–

–

–

France

–

–

–

–

–

–

–

–

–

–

USA

1.1

1.6

2.3

1.2

2.3

1.2

–

1.0 (500 kV pk)

1.1

USA (BPA)

–

–

–

–

–

NA

1.6 (± 500 kV) 1.7 (± 250 kV)

–

–

1.0

Japan

168 R. Stephen and J. Iglesias

50

Wind return/year

c

b

–

–

P-P risk (pu)

Fault inception

–

–

Reclosing

–

–

–

–

–

P-P flashover risk (pu) –

P-G risk (pu)

–

–

–

Energization

–

50

Max. volt

28

Light/clean

–

Canada

P-G flashover risk (pu)

a

Max. volt

Air clearance (and wind)

–

25

Insul. creepage (mm/ kVp-g)

Switching surge

–

Light/ clean

Power frequency

Pollution level

2.2

2.1

Norway

Table 7.15 AC values for insulation co-ordination

–

0.9

0.9

–

–

50

Max. volt

34

Middle

50

Germany

1.9 (765 kV)

–

4.6/4.4/ 0.9 3.5

3.3/2.5/ 0.9 1.9

–

–

–

–

–

50

Max. volt

–

Light/ clean

–

Korea

–

–

10–3 NA

– –

–

–

10–4

10–2

– –

–

–

–

0.7–3.0 m

27

Light/ clean

–

France

10–3

–

–

Max. volt

25

Light/clean

–

Brazil

–

–

–

–

–

–

–

1/1000 operations

5–50

Max. volt

23–54

Various

–

USA

–

–

–

–

IEEE 516 MAID

(continued)

–

–

–

–

–

– 1.6E − 3

–

–

50

Max. volt

24 * 1/26 *1

Light/ clean

–

Japan

μ − 3σ

2.0/1.7 pu

50

–

22

Very light

–

USA (BPA)

7 Influence of Compaction on the Electrical Design 169

30/40°

–

Outage rate/100 km/ year

Norway

Shielding angle

Table 7.15 (continued)

0.1

Based on required outage rate and GFD

Canada

Germany

2.0/1.1/ – 3.8

+ 5/0/ – −5

Korea

1.0

Lower than critical ls

Brazil

–

–

France

USA (BPA)

0.3–2.0

1.0 (100 miles)

− 10 to 30° –

USA

Not determ

Vary on situation

Japan

170 R. Stephen and J. Iglesias

b

–

NA

P-G (pu)

P-P risk (pu)

–

–

NA

Reclosing

–

–

P-P flashover NA risk (pu)

–

–

–

Energization

a

–

P-G NA flashover risk (pu)

Switching surge

50

50

30

Wind return per. (year)

30

Insul. creepage (mm/kVp-g)

Light/clean

Max. volt

Light/clean

Pollution level

–

Canada (Manitoba)

Air clearance Max. volt (and wind)

–

Power frequency

2.2

2.1

Norway

–

–

–

–

–

–

–

–

12.2 @ 160km/h

–

–

–

Canada (Ontario)

Table 7.16 DC values for insulation co-ordination

–

–

–

–

–

–

–

50

Max. volt

–

Light/clean

–

Korea

0.99

0.99

–

0.99

0.99

–

–

–

Max. volt

34

Light/clean

0

Germany

NA

NA

NA

NA

50

Max. volt

30

Light/clean

–

Brasil

–

–

–

–

–

–

–

–

–

–

–

–

France

–

–

–

–

–

–

–

5–50

Max. volt

–

–

–

USA

–

–

–

IEEE 516 MAID

–

–

1.6

–

–

–

–

–

USA (BPA)

–

–

–

–

–

–

–

50

(continued)

Max. volt

34 * 2/36 * 4

Light/clean

–

Japan

7 Influence of Compaction on the Electrical Design 171

c

–

30/40°

1.0

Fault inception

Shielding angle

Outage rate/ 100 km/year

Norway

Table 7.16 (continued)

0.1

30–35°

–

Canada (Manitoba)

Average no. of outages Per 100 circuit-km/ year

–

–

Canada (Ontario)

–

–

–

Korea

Light/clean

0

–

Germany –

10–3

1.0

–

< critical ls –

France

Brasil

–

–

− 10 to 30° 0.3–2.0

–

USA (BPA)

–

USA

Not determined

Vary on the situation

–

Japan

172 R. Stephen and J. Iglesias

3.3

3.2

3.1

–

–

–

–

–

–

50

Wet

Radio interference

Signal-to-noise (dB μ)

Signal (dB μ)

Noise (dB μ)

Weather/probability

Audible noise

Noise (dBA)

Weather

24

–

–

–

Korea

Wet

50

–

Foul 50%

Wet

50

–

Fair

47

49–63 above 1 71 μV/m (depends on voltage)

–

–

90%

Weather/probability

–

16–19

Canada

Max. conductor surf. – grad (kV/cm)

Norway

Table 7.17 AC values for corona effects

–

50%

42

66

24

–

90%

Peak

Brazil

Rainy

Wet

35–70 58 (depends on situation, area and time)

–

–

–

–

–

–

–

–

Germany

Wet

58

–

Foul 50%

–

Min. regulated (@1 MHz)

24

–

90%

16

France

Foul

45–55

–

–

–

-

–

–

–

–

USA

Foul

50

–

No policy

No policy

No policy

No policy

–

No policy

–

USA (BPA)

Wet condition

45–70 (depends on area and time) –

–

Wet condition –

–

–

20 ≤ (0.5265–1.6065 MHz)

–

Wet condition

15 (21:peak)

Japan

7 Influence of Compaction on the Electrical Design 173

3.3

3.2

3.1

–

Weather/ probability

–

–

–

Signal (dB μ)

Noise (dB μ)

Weather/ probability

42

Fair

Noise (dBA)

Weather

Audible noise

–

Signal-to-noise (dB μ)

Radio Interference

–

Max. conductor surf. grad (kV/ cm)

Norway

Fair

42

Fair

44

66 (@1 MHz)

90%

< 22

Canada (Manitoba)

Table 7.18 DC values for corona effects Canada (Ontario)

Fair

45

–

47

71

24

–

–

Korea

Fair

35–70 (depends on situation, area and time)

–

–

–

Germany

Fair

42

Fair

42

66

24

90%

Peak

Brasil

Fair

42

Fair

42

66 (@1 MHz)

24

90%

25

France

Fair

45–55

USA

Fair

50

No policy

No policy

No policy

No policy

No policy

USA (BPA)

Dry condit.

45–70 (depend on area and time)

Dry condit.

15 ≤

Dry condit.

20

Japan

174 R. Stephen and J. Iglesias

4.2

4.1

Inside

0.5

Where (in the ROW)

Weather/ probability

Where (in the ROW)

NA

100

Ion current (nA/m2 )

Magnetic field (μ T)

Inside/edge

Inside

Where (in the ROW)

NA

Worst weather 95% lower

Inside/outside

100

43,038

Canada (Manitoba)

Electric field 30 (kV/m)

Norway

Table 7.19 DC values for Fields Canada (Ontario)

Under outmost conductor

NA

NA

Under the out most conductor

100

Inside

25

Korea

Places of non-temporary abidiance

500

–

–

–

–

–

Germany

NA

Worst weather 95% lower

Inside/ outside

100/5

Inside/ edge

40/10

Brasil

Edge

Worst weather 95% lower

Inside/ outside

100/5

Inside/ edge

40/10

France

NA

Inside/ edge

1–5/ 7–10

USA

No policy

No policy

No policy

No policy

No policy

No policy

No policy

USA (BPA)

Edge

200

NA

–

–

In ROW

8.1 (equivalent of AC E field of 3 kV/m)

Japan

7 Influence of Compaction on the Electrical Design 175

176

R. Stephen and J. Iglesias

References 1. IEC Standard 60815-4: Selection and Dimensioning of High Voltage Insulators Intended for Use in Polluted Conditions. Part 4: Insulators for DC Systems. Edition 1.0. Oct 2016 2. CIGRE Green Book: Overhead Lines. Springer, Paris (2014). ISBN 978-2-85873-284-5. www. e-cigre.org 3. CIGRE Technical Brochure 388: Impacts of HVDC Lines on the Economics of HVDC Projects. Joint Working Group B2/B4/C1.17. Paris, Aug 2009. www.e-cigre.org 4. International Commission on Non-Ionizing Radiation Protection: ICNIRP guidelines for limiting exposure to time-varying electric, magnetic and electromagnetic fields (up to 300 GHZ). Health Phys. 74(4), 494–522 (1998) 5. CIGRE Technical Brochure 473: Electric Field and Ion Current Environment of HVDC Overhead Transmission Lines. Joint Working Group B4/C3/B2.50. Paris, Aug 2011. www.e-cig re.org 6. CIGRE Technical Brochure 792: Compact AC Overhead Lines. Working Group B2.63. Paris, Feb 2020. www.e-cigre.org 7. CIGRE Technical Brochure 831: Compact DC Overhead Lines. Working Group B2.62. Paris, Mar 2021. www.e-cigre.org

8

Case Studies

Contents 8.1 8.2 8.3 8.4 8.5 8.6 8.7 8.8 8.9 8.10 8.11 8.12 8.13 8.14 8.15 8.16 8.17 8.18

AC Case Study: Compact Plus 300 and 420 kV Lines (Norway) . . . . . . . . . . . . . . . . . . DC Case Study: Y-Shaped Insulator Strings (Japan) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . AC Case Study: Stevin Project 380 kV Line (Belgium) . . . . . . . . . . . . . . . . . . . . . . . . . . . DC Case Study: Comparison of HVDC Layouts (Germany) . . . . . . . . . . . . . . . . . . . . . . AC Case Study: Compact High Voltage Crossarms (Germany) . . . . . . . . . . . . . . . . . . . . DC Case Study: Rotating Composite Insulated Cross-arms (China) . . . . . . . . . . . . . . . AC Case Study: Low Profile 380 kV “CompactLine” (Germany) . . . . . . . . . . . . . . . . . DC Case Study: Long Distance ± 500 kV Bipole (Canada) . . . . . . . . . . . . . . . . . . . . . . . AC Case Study: Narrow Right of Way for a 500 kV Line (USA) . . . . . . . . . . . . . . . . . . DC Case Study: Prospect of Low Profile ± 400 kV Line (Spain) . . . . . . . . . . . . . . . . . . AC Case Study: Narrow ROW Tower (Japan) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . DC Case study: Development of the HVDC system (India) . . . . . . . . . . . . . . . . . . . . . . . AC Case Study: Urban Overhead Power Lines (Brazil) . . . . . . . . . . . . . . . . . . . . . . . . . . . DC Case Study: Layouts for Narrow Corridor (SUMATRA) . . . . . . . . . . . . . . . . . . . . . . AC Case Study: Live-Line Maintenance on 400 kV Towers (Hungary) . . . . . . . . . . . . AC Case Study: Small-Sized 110 kV Line (Poland) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . AC Case Study: Development and Validation of Two Compact 380 kV Towers (Germany) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . AC Case Study: Compact 400 kV Line in Switzerland . . . . . . . . . . . . . . . . . . . . . . . . . . .

178 182 184 187 192 197 206 212 213 224 226 232 238 243 246 248 254 267

Abstract

This chapter comprises eighteen cases of line compaction designs from all around the world, both in AC and DC. These cases cover different practical issues faced by real projects, providing solutions and alternatives. Some of the issues discussed in these examples are phase or pole layouts and rearrangements, crossarms designs, insulator and accessories configurations, coronarelated phenomena, mechanical loads and weather considerations, use of surge arresters, live-line maintenance works, compatibility with other infrastructures, etc.

© Springer Nature Switzerland AG 2024 R. Stephen and J. Iglesias (eds.), Compact Overhead Line Design, Compact Studies, https://doi.org/10.1007/978-3-031-44524-8_8

177

178

8.1

R. Stephen and J. Iglesias

AC Case Study: Compact Plus 300 and 420 kV Lines (Norway)

Original work on line compaction began in the 90s after concerns about magnetic fields and leukaemia in children. The original concepts were reported in [1]. New insulator technology led to further development work. Main points of the design process and final configuration are: • Cooperation STRI (a Swedish laboratory specialising in high voltage testing) and Nordic Transmission System Operators • Designed for suburban areas 300 and 420 kV • Reduce the magnetic field, compaction, delta configuration • Low visual impact • Narrow ROW, 5 m phases pacing • Tubular tower, hollow composite insulators • No groundwire • Line surge arresters, reduce overvoltages (Fig. 8.1).

Insulator Development Dimensions. The insulator assembly was developed with the following dimensions: • 6–7 m between the outer phases, • Distance outer phase—upper phase 4–6 m, • Tower height approximately 20 m (Figs. 8.2 and 8.3).

Fittings Development Full scale corona tests were conducted with the attachment of surge arrester in tower top (Fig. 8.4). Demonstration Project Rasta A demonstration project was developed using the compact tower in a suburban area. The magnetic field in the area from the existing line was above the recommended limit. The areas boasted easy access. It is important to note that the landowner was involved in the decision-making process. It was agreed to replace 3 of the existing standard towers with the compact plus towers. The conductor was altered from a simplex to a Parrot duplex configuration and the groundwire was buried in the ground (Fig. 8.5).

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Fig. 8.1 Compact plus tower

Fig. 8.2 Cross arms

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Fig. 8.3 Tower top

Fig. 8.4 Top phase with surge arrester

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Fig. 8.5 Aerial view of line section

Magnetic Field Profile Figure 8.6 indicates the reduction in the magnetic field due to the compact design and delta configuration of the compact plus tower. Technological Challenges The following technological challenges were experienced with the development of the compact plus tower: • With the reduced phase spacing, it was necessary to add a phase conductor to reduce corona noise. There is also an increased risk of conductor clashing at midspan. • Using the composite insulator as a structural element required studies be conducted relating to fibre stiffness, aging of silicon material and possible fatigue failures due to vibrations and oscillations.

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Standard Tower

Compact

Fig. 8.6 Magnetic field profile

• With the insulator as the strength component the span lengths are dependent on insulator stress. Height difference between towers and climatic conditions in the actual span needed to be taken into account. • Installation methods had to be revised as well as access plans into the area.

8.2

DC Case Study: Y-Shaped Insulator Strings (Japan)

The 500 kV Kii Channel HVDC Link, passing through a heavy polluted area, would require much longer insulator strings than those used on an equivalent AC 500 kV transmission line. Due to this longer suspension strings, the tower cross arms and horizontal distances between the main conductors would become remarkably longer. However, it is not desirable in terms of environmental impacts. Therefore, Y-shaped suspension insulator strings have been developed to shorten tower cross arms and horizontal distance between main conductors (Fig. 8.7). The tower using Y-shaped insulator strings can be more compact than those using V-shaped, because the length of cross arms and horizontal distance between main conductors of Y-shaped strings could be reduced to about 87% of that of V-shaped strings in case of the most polluted area. In Japan, for overhead power lines above 187 kV, electric power companies must consider the ROW as the horizontal distance plus 3 m in both sides of the outermost main conductors, so as not to permit construction of buildings. Therefore, it is better that the horizontal distance between main conductors becomes as narrow as possible. That’s why Y-shaped insulator strings is an effective measure to compacting tower design and reducing the width of ROW.

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Fig. 8.7 Y-shaped insulator string of 500 kV Kii Channel HVDC link

Figure 8.8 shows the decrease in the Right of Way achieved with this compact design, without an increase in the height of the tower. Several tests and studies have been carried out to determine the appropriate angle of the V-part, including pollution tests, swinging characteristics of strings test and tensile strength of insulators tests. The optimum angle of the V-part of the Y-shaped strings has been set to 110°. Forty-two insulator discs are required for the V-part and twenty for the I-part per each Y-shaped string as the most optimum structure in the heaviest polluted area.

Fig. 8.8 Comparison between Y-shaped insulator strings and V-shaped insulator strings

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AC Case Study: Stevin Project 380 kV Line (Belgium)

The Stevin project aims to upgrade the electricity grid between Zomergrm and Zeebrugge. This section covers a portion of the double circuit 380 kV line (note a portion of the line is underground). In this analysis a 525 m-long span is considered. The tension is 33.6 kN (for classical conductor) and 39.14 kN (for smooth conductor). In this case the initial sag at zero wind (16.5 m) for both types of conductors is the same. However, note that higher tensions mean a higher stress on the truss. Several analysis cases with different mean wind velocities (30 and 40 m/s) were considered. Simulations were done over 10 min interval—a duration imposed by standard recordings of wind and retained in the models of the wind fluctuations 2. In all analysis cases, the smooth-surfaced conductor was excited significantly less than the classical multistrand analogue. The tension variation (Tmax − Tmin) in the trapezoidal conductor is by 44 to 52% less than round conductors, which means a lower risk of fatigue problems. Figure 8.9 shows the mid-point evolutions of the classical multistrand conductor (above) and trapezoidal (below). Mean wind speed: 30 m/s, along wind turbulence scale: 200 m, turbulence intensity: 19%. For mean wind velocity V = 30 m/s (main analysis case), variations of the tower transverse loads ΔRy from the smooth conductor were by 34% less than from the classical analogue. At V = 40 m/s variations of ΔRy remained at the same level. In the same time, the trapezoidal conductor experienced especially significant gain in the mean value Ry (up to 46%) (shown in Fig. 8.10).

Fig. 8.9 Mid-point evolutions of the classical multistrand conductor

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Fig. 8.10 Variations of horizontal transverse load

Variations of the horizontal transverse load on tower end in the wind direction, Ry, for the trapezoidal conductor and the classical multistrand analogue. Mean wind velocity: 30 m/s, along the line, wind turbulence scale: 200 m, turbulence intensity: 19%. Example Calculation: Wind Load AC = q0 C XC G C G L d L sin2 Ω

(8.1)

q0 = 0.5 ∗ μ ∗ t ∗ V R2 (V R = wind speed)

(8.2)

With: μ = 1225 kg/m3 (for 15 °C und 101.3 Pa) t = 1 for 15 °C 25 V R = 1.08 m/s for wind zone 1 V R = 25 m/s for wind zone 2. ( Wind Zone 1 : q0 = 0.5 ∗ μ ∗ t ∗

V R2

= 0.5 ∗ 1.225 ∗ 1 ∗

25 1.08

)2 = 328.2 Pa

Wind Zone 2 : q0 = 0.5 ∗ μ ∗ t ∗ V R2 = 0.5 ∗ 1.225 ∗ 1 ∗ (25)2 = 382.8 Pa With: G C = 1.98 for a height of 15 m G L = 0.94 for L = 400 m

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Table 8.1 Wind loads

265/35 (N)

550/70 (N)

Wind Zone 1

5473.18

7916.6

Wind Zone 2

6383.9

9233.9

d = 0.0224 m for conductor 265/35 d = 0.0324 for conductor 550/70 Ω = 90°. The wind loads are shown in Table 8.1. In bundled conductors, the total effect (according to [2]) shall be taken as equal to the sum of the actions on the sub-conductors, without accounting for possible masking effect of one of the sub-conductors on another. This means that two conductors of diameter 18 mm with a combined aluminium area of 300 mm2 will impart the same load as a single 36 mm conductor with an aluminium area of 600 mm2 . Thus, from a mechanical loading point of view, the smaller number of conductors in the bundle the better. The conductor choice impacts on the tower design (which is a function of the load the tower must take) which in turn has an effect on the foundation design (which is a function of the load the foundation must bear). As a rule, the fewer number of conductors in a bundle and the lower the tensile strength of the conductor, the lower the tower strength required. Corona limitations will dictate the minimum number of conductors in a bundle and the diameter of the conductor. Insulated Cross Arms Elia (Belgium’s Transmission System Operator) uses insulated cross arms making the towers more compact, reducing the visual impact and the electromagnetic. The insulated cross arms ensure that the 380 kV line looks much the same as a conventional 150 kV tower. Existing 150 kV Line Goes Underground To build the new 380 kV line the existing 150 kV line was required by authorities to be placed underground. Figure 8.11 shows on the left the existing 150 kV line with classic mastarm (48 m high) and on the right the new 380 kV line with insulated mastarm (51 m). Impact on Landscape Here’s how the landscape will evolve north of Maldegem before, during and after the implementation of the Stevin project (Figs. 8.12, 8.13 and 8.14).

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Fig. 8.11 Existing and modified tower

8.4

DC Case Study: Comparison of HVDC Layouts (Germany)

The TSO Amprion GmbH from Germany has presented and discussed possible HVDC tower designs for a transmission capacity of 4 GW [3]. For the tower designs the bipole configuration has proven itself as the most convenient option, which fulfils the main requirements concerning system stability and interactions with other infrastructure. So there have been first conclusions in designing of tower layouts (Fig. 8.15). Part (a) presents a tower layout which has been used for the Xiangjiaba-Shanghai HVDC project for a bipolar configuration with return path by earth. The requirement for metallic return using bipole system leads to tower layout showed in part (b). In order to reduce the frequency of lightning strikes directly into the plus or minus pole, the double earthing conductors on top of the tower are suggested. This option has also an advantage comparing to one earthing conductor, that the tower height is lower and the protection level better. The next question was which converter technology should be used. Here, it has been decided to plan and design the HVDC corridors from the North to the South of Germany in Voltage Source Converter (VSC) technology. According to today’s technologies one VSC converter station can provide a maximum direct current of

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Fig. 8.12 Existing (before the project)

Fig. 8.13 During construction

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Fig. 8.14 After construction

Fig. 8.15 a Exemplary tower design for a bipolar system with return path by earth; b exemplary tower design for bipolar system with metallic return

Imax = 2000 A. To transmit the power of Ptrans = 4 GW the nominal voltage of VDC = ± 1000 kV is required. If two VSC converters connected in parallel with total direct current of 4000 A are assumed, the voltage of VDC = ± 500 kV

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Fig. 8.16 DC system configurations for 4 GW transmission power and ± 500 kV operating voltage

is sufficient. There is also an option where the converters are not connected in parallel, in which two separate bipoles are considered (Fig. 8.16). In the next step, environmental and operational aspects have been considered. It should be possible to maintain the faulty pole on the tower as shown in Fig. 8.16 while the other pole is still in operation. If only one pole is available the direct current path closes in the neutral conductor, so that the neutral conductor may experience (depending on the length of the DC link and applied conductors) voltages in medium voltage range (for example 400 km · 10 mΩ/km = 40 kV). Moreover, due to backwards strike and commutation process even higher voltages may occur. For these reasons the clearance distance to neutral during climbing

Fig. 8.17 a Tower design with one bipole system; b tower design with two bipole system

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on the tower to faulty conductor need to be assured. From this point of view, the best option would be to have two neutral conductors located on both tower sides as shown in Fig. 8.17. In such case, one tower side could be completely disconnected for maintenance activities and the climbing on disconnected tower side would be possible without considered restrictions. With neutral conductors located beneath the conductors under operating voltage additional beneficial effects on environmental impact can be achieved. Such neutral conductors will significantly reduce the electric field in the Right of Way and they will partially collect the ions generated on upper conductors, so that the secondary effects connected with charging of objects in Right of Way can be minimized. Pros and Cons for Discussed System and Tower Layouts • Environmental impact – Both towers fulfill federal emission control regarding the electric and magnetic fields and other emissions – Both towers have similar Right of Way – Tower a is higher than tower b. • Availability – In case of a failure (earth fault as consequence of lightning strike) auto reclose would lead to a power loss of 50% for tower a and 25% for tower b – In case of maintenance of one tower side, the availability is 50% for both towers – In case of maintenance on one of the converters and in case of failure of one of the converter, 75% of total power will be available for both towers. • Total system losses – By using the same conductors tower a has higher losses than tower b. • Conversion to AC – Only a small impact on the tower height for both towers. In conclusion, the evaluation of proposed designs shows that there is no best option for the system and tower design on this early planning stage. The following major criteria should be considered for choosing the appropriate system configuration and design of the HVDC tower: • Environmental impact: the dimensions of the tower (height and Right of Way), possibility to use conductor technology and reduction of emission levels below required limits • Technology performance characteristics: operational aspects like system stability and availability • Costs: financial aspects like transmission losses and investment costs • Sustainability: flexibility in the future like conversion back to AC with many stepdown transformers.

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AC Case Study: Compact High Voltage Crossarms (Germany)

The general parameters and requirements are summarized as follows: • Calculation of parameters according to EN 50341-2-4 [4]. • 420 kV two-circuit overhead power line design with suspension towers. • Use of 4 bundle conductor 565-AL1/72-ST1A—FINCH according to EN 50182. • Possible operation in wind load zone W4 according to German NNA [4] (characterized by 30 m/s reference wind speed and ice load zone E2 with ice load of 10 N/m + 0.2 × conductor diameter [mm]). • Wind span length 500 m. • Crossarm design to be used also for 420 kV DC application (34 mm/kV CD). • Max. electrical field at the insulator triple point = 4.5 kV/cm; at arcing rings = 21 kV/cm. • Rated short current = 50 kA, 1 s. • Compliance with German protective law of emissions (“26. BImSchV”). It contains requirements for the protection of the public to guard against harmful environmental effects by electric, magnetic and electromagnetic fields. • Mechanical requirements are based on Load cases [4], (Table 8.2). – Loading Case A: Permanent loads and wind action, corresponding conductor horizontal tensile forces at + 5 °C. – Loading Case D: Permanent loads and wind action together with ice loads, corresponding conductor horizontal tensile forces at − 5 °C. – Loading Case J: Unbalanced ice loads. – Loading Case L: Permanent loads and ice loads, corresponding horizontal conductor tensile forces at – 5 °C; failing of one insulator string of a multiple insulator set. Note: effects of loading case L are only decisive for crossarms. Design of the Insulator Crossarms Based on the maximum mechanical stresses first two different versions of nonpivoting cross-arms by using exclusively composite insulators have been created. Table 8.2 Mechanical loads

Load case Load direction Calculated mechanical load (kN) A

Vertical Horizontal

67.96 72.33

D

Vertical Horizontal

68.66

J

Vertical

90.13

Longitudinal

121.67

133.05

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Fig. 8.18 Non-pivoting Vee (NPV)

One with fixed clamps/80° horizontal angle between posts and one with clamps with controlled slippage/50° horizontal angle. The reason was the high longitudinal mechanical loads (Load case J). For keeping the vertical loads, two suspension rods have been designed. The insulators for both versions are identical (Figs. 8.18 and 8.19). Together with the hardware manufacturer all connecting parts with respect to mechanical loads and short circuit current have been designed. Intended Investigations and Tests After fixing the main design parameters as insulating length, core diameter, creepage distance, arcing distance ultimate mechanical loads (incl. safety factors), connecting dimensions to the tower following activities have been started: • • • •

Electrical field calculations Determination of properties of various glass-fibre reinforced plastic (FRP) rods Mechanical stress calculation Calculation of load transposition.

With reference to the results of the calculations, the prototypes of insulators as well as the fittings were manufactured for the necessary practical tests. The following tests have been carried out:

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Fig. 8.19 50° horizontal angle, slippage clamps

Mechanical Tests for Verification of Combined Mechanical Static Loads • Dielectrical tests including radio interference voltage (RIV). In addition, DCvoltage tests and corona extinction test • Power arc tests • Buckling tests of post insulators • Load transposition tests. The requirements of the compact designs were a new quality of mechanical stress. In order to create optimum designs, it was decided to determine different parameters as tension, pressure, modulus of elasticity, shear modulus of different polymer-rods. The results were used for optimization the mechanical calculations. As first positive result the calculation of critical load case J with extreme longitudinal tensile load showed positive results for 50° design with fixed clamps. The static deformation is shown in Fig. 8.20 (Fig. 8.21). With this positive calculation the mechanical tests were started with the 50° version and fixed suspension clamps. After strengthening the connecting parts to the tower (strong deformation at 125% of calculated longitudinal load (Load case J), the design withstood 200%. As consequence it was decided to stop the

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Fig. 8.20 Static deformation for load case

Fig. 8.21 Laboratory test arrangement

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Fig. 8.22 Power arc test

development of suspension clamps with controlled slippage and to carry out all following tests with 50° NPV with fixed clamps. The dielectric tests fulfilled the standard requirements. In addition, the complete crossarm was tested at + 555 kV DC voltage for 30 min. The power arc tests according to IEC 61467 [5] have been carried out under following test parameters: • Test circuit: D • Specified arc current: 50 kA • Specified arc time: 0.2 s; 0.2 s; 0.5 s (Fig. 8.22). The crossarm design passed all tests. The final mechanical tests (residual strength of elements) showed for the suspension rods higher tensile strength as Specified Mechanical Load (SML). Buckling tests: To verify the calculations and to get more information for the real buckling strength the single post insulators have been tested according to load cases Euler 2 and 4 (Figs. 8.23 and 8.24). To cover also the very special load case L, breakage of one suspension insulator, it was decided to carry out this test at outdoor facility (Figs. 8.25 and 8.26). The application of the technology is demonstrated in Figs. 8.27 and 8.28. In conclusion, due to the different designs of string configurations for 420 kV, many calculations and practical tests have been carried out. The main result was that the use of suspension clamps with controlled slippage is not necessary for the NPV with small horizontal angle. Also, an important target of this project was, to verify the results of the calculations by real tests. Especially for the mechanical parameters a good conformity could be demonstrated. The developed 420 kV insulating crossarm can be used also for 420 kV DC application. This design can be fixed to towers made by concrete (UHPC), steel or to lattice towers.

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Fig. 8.23 Buckling Euler test

8.6

DC Case Study: Rotating Composite Insulated Cross-arms (China)

Combined with the present status of the research and application of composite insulated cross-arm (CICA) tower, taking Lingzhou-Shaoxing ± 800 kV UHVDC transmission line engineering as research background, this case study put forward the force mechanism and designing scheme of rotating CICA, and carried out simulation analysis based on tower-line couple model. The analysis results show that the rotating CICA freely moves under the longitudinal unbalanced tensions, so the longitudinal unbalanced tension can be released, the stress of CICA and tower can be reduced, and the weight of tower and the cubic amount of concrete foundation can be effectively reduced, which has good economic and social benefits (Figs. 8.29 and 8.30). For UHVDC line towers, the requirement for structure size and insulation performance is high, and the load and the force to components are large, especially under the condition of broken line or uneven iced, which will produce large longitudinal unbalanced tension. For a conventional tower, the load is resisted by the structural bearing capacity. The longitudinal tension usually causes composite

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Fig. 8.24 Buckling Euler test 4

cross arm components to bear a large force, which is not conducive to the design and construction of the composite cross arm. So how to release the unbalanced tension becomes the focus of research on UHVDC line CICA tower. This paper put forward a design scheme of rotating CICA through research. Working Mechanism The rotating CICA is a planar triangular structure composed of one composite insulator and one post insulator. The node can be rotated back and forth by the connection of rotating node and tower body, as shown in Fig. 8.31. In general, the post insulator transmits pressure, and the composite insulator transmits tension. When the front and rear side conductor generates longitudinal unbalanced tension, the rotating CICA rotates to the side with a large tension around the rotating node. In the case where the length of the front and rear side conductor remains unchanged, the span and the tension become smaller for the side with larger tension, and for the side with small tension, the span and the tension become larger. The rotation will stop until the front and rear side tensions are equal, reaching

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Fig. 8.25 Testing arrangement

Fig. 8.26 After test initiated breakage at conductor side

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Fig. 8.27 Application: Wintrack, Tennet, the Netherlands

a new balance. When the longitudinal unbalanced tension disappears, the combined insulators will rotate in the opposite direction, returning to the previous state automatically. Simply, the working mechanism of the rotating CICA is “tension to drive, rotation to release, conductor to constraint”. For example, when uneven icing occurs, the process of tension change for CICA front and rear side conductor is shown in Fig. 8.32. Design Scheme The main design conditions of the line are shown in Table 8.3. The rotating CICA is made of insulated material, which realizes the unification of functional materials and structures, but there is no relevant design method for composite cross arm insulation configuration at present. In the initial determination of the insulator length, we referred to the 750 kV composite cross arm test results and the previous ± 800 kV line composite insulator test results. Meanwhile, we also considered the beneficial effects of the composite insulator oblique placement. Then we determined that the effective insulation length of the composite material should be not less than 9300 mm.

8 Case Studies Fig. 8.28 Eagle Towers. Ability to change tower design with compact insulator design. Energinet, Denmark

Fig. 8.29 Conventional steel tower for ± 800 kV UHVDC transmission line in China

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Fig. 8.30 Rotating CICA tower for ± 800 kV UHVDC transmission line in China

Fig. 8.31 Composition of rotation CICA

Structural Finite Element Simulation Analysis Since the composite material rotation cross arm is one mechanism in longitudinal direction, so the structural analysis cannot be performed. After the tower line coupling model is adopted and rotation CICA has formed a stable structural system with strong geometric nonlinearity, the structural analysis and calculation can be carried out. The six-tower and seven-line coupling model is shown in Fig. 8.33. For the six-tower and seven-line tower-line coupling model, the internal forces and rotation angles of each component of the rotating CICA tower under each working condition can be obtained by applying loads. After that, we can carry out structural design. The rotation angles of CICA are as shown in Table 8.4. It can be seen from the Table 8.4, that for the condition of no unbalanced tension (such as strong wind 60°), the angle of rotation of the CICA is very small, so it can

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Fig. 8.32 Drive and balance process by tension Table 8.3 Design conditions Project

Design conditions (value)

Project

Design conditions (value)

Altitude (m)

1500

Pollution class

Heavy pollution

Terrain

Plain

Conductor

JL/G3A-1250/70

Groundwire

LBGJ-150-20AC

Optical groundwire

OPGW-150

Basic wind velocity (m s−1 )

27

Icing (mm)

10

Horizontal span (m)

460

Vertical span (m)

550

Fig. 8.33 Tower-line coupling model with six towers and seven lines

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Table 8.4 Rotation angle (°) Case

Grade 1

Grade 2

Grade 3

Grade 4

Grade 5

Grade 6

Strong wind 0°

2.22

3.63

4.37

4.49

3.94

2.53

Strong wind 45°

1.29

2.03

2.34

2.28

1.91

1.23

Strong wind 60°

0.15

0.20

0.22

0.22

0.20

0.14

Uneven icing

2.53

5.29

5.78

5.78

3.63

1.75

Broken line

5.22

2.89

0.12

0.12

0.12

0.12

be considered that rotation does not occur. Mechanical analysis can be performed as conventional cross-arm. For 0° strong wind, 45° strong wind, broken line and uneven iced conditions, the post insulator rotates due to the unbalanced tension. The maximum rotation angle occurs at the uneven iced condition, which is 8.63° and the corresponding end displacement is 1.41 m. However, under other normal operating conditions, the rotating angle of CICA is small, and the tension can be released by slight adjustment of the front and rear side sag, thereby reducing the stress of CICA. This is beneficial to the composite cross arm design. Economic Analysis The economic comparison analysis between the rotation CICA tower and the conventional angle steel tower is shown below. As can be seen from Table 8.5, compared with the conventional angle steel tower, the rotating CICA tower material is reduced by 33%, weight is reduced by 20%, the concrete foundation is reduced by 53.2%, and the comprehensive cost is reduced by 17%. The economic efficiency is very prominent, mainly caused by the following aspects. • Nominal height is reduced by 7 m. Due to the cancel of the suspend insulator string, the height of CICA towers is reduced by 7 m compared with conventional V type string tower under the same service conditions, which has reduced the effect of the conductor load effectively. The main tower body material is reduced from Q420L180 × 16 to Q420L160 × 14. • Wind load is reduced at head of tower. Because only two insulators are used in CICA tower, the wind-shielding area is much smaller than that of conventional angle steel tower, and the wind load on the head of tower is correspondingly reduced. • Release of longitudinal unbalanced tension. Because the tower can rotate freely in the longitudinal direction, the unbalanced tension can be released. And the tower is not bearing the unbalanced tension in the longitudinal direction anymore. The diagonal member of the tower body is reduced from L110 × 7 to L90 × 7, which is reduced by 3 grades. It can be concluded that the working mechanism of the rotating CICA is “tension to drive, rotation to release, conductor to restraint”. The longitudinal

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Table 8.5 Economic analysis of rotation FRP cross arm (RMB) Conventional tower

Project Nominal height (m) Pulling force on foundation (kN)

CICA tower

Reduction

Save %

52.00

45.0

7.0

13.0

1122.00

665.0

457.0

41.0

Corridor width (m)

20.30

19.9

0.4

2.0

Material quantity

36.50

24.5

12.0

33.0

Weight compos. insul (T)

0.00

4.7

− 4.7

− 100.0

Found. concrete (m3 )

80.36

37.6

42.8

53.0

Foundation steel (T)

3.67

2.3

1.4

37.0

31.39

21.1

10.3

Composite insulator

0.00

13.0

− 13.0

− 100.0

Installation and transport

6.20

5.0

1.2

20.0

Foundation fee

18.40

9.0

9.4

51.0

1.60

0.0

1.6

100.0

48.0

9.6

17.0

Cost (k)

Weight angle tower (T)

Angle tower

V string Total

57.6

33

unbalance tension of the conductor can be effectively released, and the force of the cross arm and the tower body can be reduced. Referring to the 750 kV composite cross arm test results and the previous experimental results of ± 800 kV line composite insulators, we determine that the effective length of composite insulators should not be less than 9300 mm, considering the favourable effect of oblique placement of composite insulators. In order to reduce the pole spacing, compress the width of the corridor, and avoid the short-connection between the hanging board and post insulator string, the maximum upward angle of the post insulator is 20°. Because the rotating CICA tower is a mechanism system in the longitudinal direction, the mechanical analysis cannot be carried out. So we bring in conductor constraint to form the tower-line coupling system. The comparison analysis shows that the maximum error of the model is just 0.7%, which can accurately study the change of rotation angle, conductor tension and sag of CICA. It can be seen from the simulation analysis that under the condition of no unbalanced tension (such as strong wind 60°), the force mechanism is as same as the conventional tower; Under the condition of unbalanced tension, the post insulator rotates, and the front and rear side sag slightly adjusts, so that the tension is released effectively to reduce the stress of the component. Compared with the conventional tower under same conditions, the weight of CICA tower is reduced by 20%, the foundation concrete is reduced by 53%, and

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the comprehensive cost of the main body is reduced by 17%. This shows that CICA has great economic advantage.

8.7

AC Case Study: Low Profile 380 kV “CompactLine” (Germany)

In Germany, grid expansion plans by transmission system operators increasingly face a severe lack of acceptance in public perception. This leads to long approval processes for grid expansion projects, thwarting grid expansion in the German transmission system. With the objective to develop, test and demonstrate an innovative and compact overhead power line design for 380 kV, the research project “compactLine” was started in 2013. The project consortium consists of a German transmission system operator, industry partners and research institutes. The new overhead power line design aims at significantly reducing Right of Way as well as overall height of the transmission corridor without increasing the number of pylons. Nevertheless, any new overhead power line design has to be operated in an existing transmission grid efficiently without compromising security of supply. In order to facilitate the technical development, it was crucial to define a set of specific requirements to be met by the new overhead power line design. Requirements by the TSO • Development of the new overhead power line design according to EN 50341 [4] • 380 kV two-circuit overhead power line design with suspension and tension pylons • Use of standard conductor bundle 4 × ACSR 434-AL1/56-ST1A with an overall ampacity of 3600 A • Minimum ground clearance of 12.5 m • Possible operation in wind load zone W2 according to EN 50341-2 [4] (characterized by 25 m/s reference wind speed and ice load zone E2 with ice load of 10 N/m + 0.2 × conductor diameter [mm]) • Inspection and maintenance works on conductors and cross-arms without need for cranes or manlifts • Safe accessibility of one cross-arm with the circuit switched off while the other circuit is operated at 3600 A • Resulting corridor dimensions not more than 60 m width and 40 m average height at span lengths of approx. 420 m • Compliance with German regulation “26. BImSchV” [6] for electromagnetic field emissions under maximum load: 5 kV/m and 100 μT at 1 m above ground and audible noise at max. 35 dB(A) in residential areas at night according to “TA Laerm”.

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Fig. 8.34 “CompactLine” suspension bundle spacer for quad bundle and a double steel rope

Development of Phase Conductor Configuration The main technical feature of the “compactLine” concept to reduce the Right of Way as well as the corridor height is the addition of two highly tensioned steel ropes to the phase configuration. Each of the phase conductor quad bundles is attached to the steel ropes like garlands by suspension bundle spacers (Fig. 8.34). The distances between the bundle spacers will be approx. 20 m. Thus, the sag of the subspans is typically below 1 m and overall conductor sag is significantly lower than of a conventional system. A comparison is given in Table 8.6 and Fig. 8.35. Development of Insulators Due to the high tension of the conductors, also lateral movement of the conductors is limited. To take full advantage of this behaviour, rigid V-string arrangements without lateral movement were chosen. However, this conductor configuration concept leads to a series of technical challenges. Besides of bundle spacers also the insulator string sets and fittings had to be newly developed. One of the challenges was the design of composite insulators fulfilling the strong tension requirements caused by the highly tensioned steel support ropes. During the research phase, three alternative suspension insulator string configurations as well as one design Table 8.6 Conductor sag comparison of conventional and compact line configuration Conductor temperature (°C)

Conventional sag (m)

“Compactline” sag (m)

+ 10 (EDS)

17.3

6.0

+ 80

19.6

6.5

−5

17.8

8.1

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R. Stephen and J. Iglesias

Fig. 8.35 Conductor sag comparison of conventional and compact line configuration

Fig. 8.36 Three alternative “CompactLine” phase configuration concepts for the suspension pylon

for tension strings, were investigated and tested for mechanical and electrical performance (Fig. 8.36). Depending on the phase configuration, core diameters of 88, 130 and 170 mm were developed and tested successfully to withstand the tension as well as compression loads with corresponding safety factors. In order to facilitate the final development of the overall overhead power line design, decision was made to focus on the “Havel” configuration for a latter demonstration project. Tension insulators had to be developed, as tensile forces under everyday stress (EDS) conditions are much higher than of conventional systems in Germany. A very long V-string arrangement was chosen for the tension string set of the support ropes. Here also a special turnbuckle construction set allows sagging of support rope and suspended bundle. In order to withstand failure of one insulator in the string, tension insulators were designed with a 63.5 mm composite core for 1320 kN. Respective design tests according to IEC 61109 were performed successfully (Fig. 8.37).

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Fig. 8.37 “CompactLine” tension insulator concept

Development of Pylons Due to the highly tensioned steel ropes between the tension pylons, high tensile forces are acting on the cross-arms resulting in high bending forces acting on the pylon. Therefore, conical solid-wall steel pylons were investigated instead of a latticed steel tower to bear the increased forces and to reduce the dimensions of the pylon at the bottom. Moreover, this reduction of the pylon diameter will also have a positive impact on land use (Fig. 8.38). The suspension pylon was designed as single tubular, conical steel tower with ring flange connections, based on the proven concept of wind pylons. For the design of the pylons, maximum pylon foot diameter was limited to 3.8 m to allow for road transport logistics, accessing railway crossings and tunnels. The height of each single segment was limited to 12 m, the weight to 20 t. These limitations are owed to difficult conditions for transport in rough terrain and remote areas.

Fig. 8.38 Tension pylon concept (left) and suspension pylon concept (right)

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Table 8.7 “CompactLine” designed pylon dimensions for suspension and dead-end pylon

Diameter (foot) (m)

Suspension pylon

Dead-end pylon

~ 2.5

~ 3.4

Diameter (head) (m)

~ 1.5

~ 2.5

Pylon width incl. cross-arm (m)

~ 39

~ 36

Pylon height (m)

~ 30

~ 36

Furthermore, the height of each element was defined to be a whole multiple of 3 m, which corresponds to the common width of heavy steel plates. High utilisation rate of the pylon shell especially in the lower parts calls for the use of T-flanges as applied at the base of wind pylons as well. Therefore, provision is made for a manhole in the lower part of the pylon to allow for a regular inspection of the bolts with safe access. The dead-end pylon (also possible as tension pylon) was designed as a portal, consisting of two tubular, conical steel pylons supporting the cross-arm. This is related to significantly higher forces resulting from steel rope tension. An overview of the dimensions of the suspension and dead-end pylon are listed in Table 8.7. Mechanical and Electrical Tests In order to validate the technical development of components and comply with respective standards, several mechanical and electrical full-scale tests were carried out. As one example, suspension as well as insulator string configurations were tested in a full-scale outdoor test set-up for the situation that one of the tensioned insulators fails (load transposition). The remaining insulator(s) had to be able to withstand the dynamic forces due to accelerations and impacts during its movement to the new position of equilibrium. Moreover, relevant components of the “compactLine” system were subject to several electric tests, such as dielectric, short-circuit and switching impulse tests (Figs. 8.39 and 8.40). Satisfyingly, all mechanical and electrical tests were passed successfully with minor optimizations of some of the components. Acceptance Study However, experiences suggest that this purely technological approach might not be able to meet acceptance challenges accordingly. Consequently, the technical development of the “compactLine” overhead power line design was supported by a detailed communication plan and validated by an independent acceptance study. The study revealed among other results, that height of the pylons is a major factor to influence acceptance of an overhead power line. Hence, there is evidence that an overhead power line concept with reduced height such as “compactLine” can indeed influence public acceptance positively.

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Fig. 8.39. Mechanical load transposition test on CompactLine “Saale” configuration

Fig. 8.40 Flashover during switching impulse test on tension insulator configuration

Demonstration Based on the satisfying and promising results of the research as well as on the acceptance study, the construction of a pilot project was approved. The overhead power line project has a length of 1.8 km consisting of three “compactLine” suspension towers as well as two “compactLine” tension towers, connecting an existing substation with a nearby passing overhead power line. The line was successfully commissioned in summer 2018 and fully operational.

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Fig. 8.41 “CompactLine” overhead power line. Last works before commissioning in summer 2018

After commissioning, a technical monitoring program of the pilot overhead power line operated in the existing grid shall provide insights in operation and maintenance of the “compactLine” concept (Fig. 8.41).

8.8

DC Case Study: Long Distance ± 500 kV Bipole (Canada)

The ± 500 kV HVDC Bipole III connects the generation source at the Nelson River in Northern Manitoba with the load centre located near Winnipeg in the South, adding 2000 MW of renewable energy to Manitoba Hydro’s high voltage direct transmission capacity. Each pole consists of three-bundled conductors supported by steel lattice towers with a total circuit length of 1384 km. The line was energized in 2018 [7]. The tower top geometry design of Bipole III is a balance design between electrical clearance, lightning failure rate, live line maintenance and cost. The cross-sectional tower top geometry of Bipole III line is mainly directed by the following items: • The clearances between conductors and the tower during still air and swung positions that should prevent flashover between conductor and tower metal parts. • Minimal approach distance (MAD) under swung positions to allow live line maintenance. • Shield angle of the groundwire required to limit the probability of lightning related faults to an accepted value.

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• Mid span clearance between conductors to prevent pole-to-pole flashover when conductors are in movement either due to wind, ice, or in a galloping mode. Both I-string insulator and V-string insulator were considered during initial tower design. After detailed comparison, the cost of I-string tower design and V-string tower design are closed to each other. As existing Bipole I and II are using I-string configuration, the I-string tower design was selected for Bipole III due to ease of maintenance (same live line tooling can be utilized). As the line route traverse through various weather zones and terrains, a full weather study along the proposed line route had been completed. Based on such study, five different weather zones are established to optimize tower design and increase line reliability which is shown in Fig. 8.42. The electrical clearances for insulator swing out are listed in Table 8.8. Live line maintenance is one of the criterial requirements for tower design. Manitoba Hydro practices live line maintenance works and observes and maintains MAD at maximum wind speed of 40 km/h in which a live line crew could work under. All tower designs of Bipole III need to provide the sufficient clearance for both bare hand method and hot line stick method. Due to this requirement, the MAD becomes the governing clearance for tower geometry design in some sections of Bipole III. Bipole III transmission line is located in Manitoba, where the ice or wet snow on conductor is common phenomenon. With moderately strong wind in the prairie, galloping could happen easily on the transmission line. Galloping of conductors can lead to short-circuits between the two poles or between one pole and the groundwire for middle span clearance. As discussed in Sect. 4.5, there is no proven anti-galloping device used on HVDC line, so Manitoba Hydro has designed the tower to withstand such event (Category 3 method in Sect. 4.5). The calculation of clearances between conductors during galloping is done by software. Since galloping can occur with a small thickness of ice, the weather condition defined for this calculation consists of 5 mm of radial ice and a wind pressure of 150 Pa based on the weather study. Both single loop and double loop were included for tower design. Single loop was considered for long span (up to 480 m) to ensure the reliability of Bipole III line according to the past experience. After the consideration of all above design factors and parameters, the tower geometries of suspension tower of Bipole III for different weather zone are shown in Fig. 8.43.

8.9

AC Case Study: Narrow Right of Way for a 500 kV Line (USA)

A major utility with operations in the south-eastern United States has been experiencing significant growth, mainly from industrial development. Planners determined that additional 500 kV transmission capacity is needed to service the area. The existing standard tower at 500 kV required a 69 m Right of Way. Due to

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Fig. 8.42 Weather zone of Bipole III in Manitoba

the short lead times associated with some of the industrial development projects and the difficulty in acquiring the standard Right of Way on a timely basis to facilitate the development projects, the design team identified a need to explore ways to compact the design. The planners suggested that the line design team explore ways of fitting a new 500 kV line with an ampacity rating of 3000 A in an existing 230 kV corridor which is 38 m wide. This would eliminate the need for the lengthy Right of Way acquisition process.

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Table 8.8 Electrical clearances for insulator swing-out. Manitoba Bipole III Weather zone

Wind pressure (Pa) North

Still air

North AB

North CD

Central

South

Minimal required clearance (m)

–

–

–

–

–

3.5

Cigre (1% wind)

177

191

254

205

205

3.2

1 h yearly wind

318

344

458

370

370

2.5

90% design wind

734

853

1201

971

971

1.2

100% design wind

906

1055

1494

1199

1199

1.0

To determine the requirements and parameters that impact this specific effort, the team qualitatively assigned priorities to common performance metrics and the design parameters that impact those metrics. Following the qualitative assignment of importance to key performance measures, the team studied the related parameters. A parametric study was performed based on some assumed limits of application to highlight which of the related parameters had the greatest impact. Based on the results of the parametric study, the important parameters were studied in more detail to determine their actual limits of application. The detailed study results allowed the development of configurations with varying levels of compactness. Numerous configurations were developed considering parameters ranging from standard approaches to the limits determined through the detailed analysis of those requirements. The advantages and disadvantages of the various configurations were then compared to support selection of the preferred configurations. The final design step included the detailed design of the towers for implementation within the utility’s set of standards for use on future projects. Parameters and Compaction Limits A parametric study determined which priority parameters should be studied in detail to determine limits of compaction. The parametric study considered varying phase configurations, tower dimensions and conductor configurations. The study produced results for the predetermined key performance measures: • Achievable span length as limited by conductor blowout and correlated ROW clearance requirements including vegetation buffers. • Audible noise and EMF at the ROW edge.

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Fig. 8.43 Suspension tower geometries. Bipole III in Manitoba

Five generic phase configuration categories were defined: 1—Horizontal, 2—Vertical, 3—Delta, 4—Inverted Delta, 5—Rotated Delta. For each configuration, there are a variety of options including whether the phases are separated by supporting structural elements or whether the insulation system is I-String or V-String. Furthermore, tower dimensions are determined by required spacing between phases and between each phase and structural elements. These spacing requirements will vary per the following:

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• • • •

217

Required clearances based on switching transient overvoltage studies Insulation requirements resulting from insulation coordination studies Insulation arrangements including selection of V-string versus I-string Line layout including span lengths and resulting impacts on galloping performance.

The detailed studies required to define these parameters are not possible without a selected configuration. Therefore, the parametric study considered varying tower dimensions to support understanding of the impact of phase configuration and tower dimensions on the studied performance measures. The range of tower dimensions considered was intended to describe possible arrangements. Five tower dimensional cases were considered for each phase configuration. The tower dimensional cases were assigned numeric descriptions, 1 being the most compact configuration considered and 5 being the least compact configuration considered. The tower dimensional ranges are described in Fig. 8.44. Subsequent analysis indicated if the phasing configuration and tower dimension combinations were technically feasible or even necessary to achieve the project objectives. Notes: • The gray hatching describes regions reserved for structural supporting elements. • The red circle describes the phase bundle locations for the configuration. To support a high-level understanding of the conductor configuration impact on the key performance measures, the conductor diameter, bundle quantity and bundle spacing were varied while meeting project requirements. The conductor configurations considered included three bundle and four bundle configurations with

horizontal

vertical

compact

compact

Fig. 8.44 Tower dimensional cases

delta

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Fig. 8.45 Span lengths achieved

varied conductor diameters and bundle spacing. The parametric study included the following: • Five phase configurations (Horizontal, Delta, Inverted Delta, Rotated Delta, Vertical) • Five tower dimensional cases (1 = Most Compact through 5 = Least Compact) • Two bundle quantities (3 or 4) • Five conductor configurations. Figure 8.45 describes the achievable span length as limited by the project blowout criteria for each phase configuration and tower dimension case. The achievable span lengths vary from very small to approximately 1200 ft for the studied configurations. For some dimensional cases, the Horizontal phase configuration couldn’t achieve realistic span lengths. The Vertical phase configuration achieved the maximum achievable span length. Figure 8.46 describes the achieved audible noise values at the edge of the ROW for each phase configuration, tower dimensional case and conductor configuration. As the tower dimensions decrease (more compact) the audible noise increases. Increasing the number of subconductors in a phase bundle from 3 to 4 reduced the audible noise value by approximately 5 dBA. Increasing the subconductor diameter reduced the audible noise value. Decreasing the bundle spacing also reduced the audible noise value, by a smaller amount. Plotted results containing the descriptor 3 describes a 3-bundle configuration, while the descriptor 4 describes a 4 bundle configuration. The descriptor “A” describes the smallest bundle diameter while “E” describes the largest bundle diameter. Of the key performance measures studied, the audible noise and achievable span as limited by conductor blowout constituted the greatest challenges to the project. Other studied parameters did not approach the selected limits. The approximate analysis contained within this study indicated that some of the studied tower and

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Fig. 8.46 Audible noise analysis

conductor configurations can achieve desired audible noise performance, while others may require some adjustment to comply. The achievable span length can be considered a cost indicator, with the larger achievable span lengths indicating the expected lower overall cost when applying the selected tower and conductor configurations to a line. The Horizontal phase configuration results in the highest audible noise values and the smallest achievable span lengths, therefore the worst performer of the phase configurations considered. The three Delta type phase configurations all have very similar results. The Vertical phase configuration achieves the largest achievable span lengths with slightly higher audible noise values when compared to the Delta type configurations. Based on the parametric study results, the following analyses were performed on some of the most feasible configurations: • Transient Overvoltage analysis • Insulation Coordination analysis • Live-Line Working Distance analysis. Minimum clearance requirements and insulation lengths determine limits to compaction. A reduction in required clearance or reduction in required insulation length can result in a more compact tower design. The detailed study to define compaction limits generally supports reduction in values historically applied. Reduction in such limits facilitates the development of a relatively compact tower. Although, there are some noted disadvantages to reduction in clearances including some expected reduction in performance, difficulties in live working and changes to standard insulation assemblies. The compaction limits were studied in detail to determine how compact the tower design could be; the need and efficiency of applying such limits was determined in subsequent design steps.

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Fig. 8.47 Tower configuration comparison

Tower Configuration Comparison Possible tower configurations were compared to facilitate the selection of a preferred configuration. The approach to the comparisons included the development of candidate tower configurations based on previously studied constraints, followed by the selection of a short-list of tower configurations for in depth comparison. Figure 8.47 describes the short-list configurations studied (Table 8.9). The maximum allowable span length as limited by conductor blowout and ROW edge clearances was determined for each tower configuration and used as the design span for that configuration. This approach of applying the maximum allowable span as the design span reflects the notion that the optimal design span for each configuration is the maximum span allowed by this criterion. However, it is noted that the cost savings correlated to maximizing span lengths is not always realized given the number of constraints that can disallow long spans in a given corridor such as vegetation, line angles, and pinch points in the ROW. Tower heights were selected to support the required ground clearances in the design span assuming flat terrain. In addition to the noted quantitative comparison, a qualitative comparison described the relative performance of each configuration in performance measures which are not easily quantified. The last comparison item included a cost comparison between each of the options on a per mile cost basis. The estimated cost comparisons were only intended to consider costs that vary with each tower configuration and did not consider overheads, access constraints, ROW, mobilization,

Unit

Rotated delta, 1 pole Compact spacing

Vertical, 1 pole Standard spacing

Pass

Pass

Qty

Qty/str

Pass/Fail Fail

Pass/Fail Fail

Number of shield wires

Number of foundations

Standard insulator assy

Standard insulators

Live-line maint. Pass/Fail Fail

1

2

3

Qty

Number of subconductors

Pass

1

1

3

185

125

Ft

34,100

1150

Estimated structure height

875

16,900

Ft

Estimated Lb/str structure weight

Achievable span length

Pass

Pass

Pass

2

1

3

175

33,500

1150

Vertical, 2 pole braced Standard spacing

Structure configurations

Configuration parameters and analysis results

Component

Structure configuration results

Table 8.9 Summary of analysis results

Pass

Pass

Pass

1

2

3

135

20,100

825

Rotated delta, 1 pole Standard spacing

Fail

Fail

Fail

1

1

4

165

30,600

1150

Vertical, 1 pole Compact spacing

Fail

Fail

Fail

2

1

3

155

32,100

1000

Rotated delta, 2 pole Compact spacing

Fail

Fail

Fail

2

1

4

160

34,300

1150

Vertical, 2 pole braced Compact spacing

Pass

Pass

Pass

2

1

3

185

46,200

1150

Vertical, 2 pole w/ arms Standard spacing

Pass

Pass

Pass

2

2

3

130

28,000

875

Delta, 2 pole Standard spacing

Pass

Pass

Pass

2

1

3

180

41,200

1000

Rotated delta, 2 pole Standard spacing

(continued)

Fail

Fail

Fail

2

2

4

125

28,800

1000

Delta, 2 pole Compact spacing

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Unit

3

3

1

2

1

1

Aesthetics

Design flexibility

Structure constructability

Foundation constructability

Wire constructability

Line restoration

5

3

2

1 = best 5= worst

Rotated delta, 1 pole Compact spacing

1

1

5

4

5

4

3

1

4

Vertical, 1 pole Standard spacing

5

5

3

5

5

2

4

1

3

Vertical, 2 pole braced Standard spacing

Structure configurations

Galloping performance

Switching performance

Lightning performance

Qualitative comparison

Component

Structure configuration results

Table 8.9 (continued)

1

1

3

1

3

4

1

1

1

Rotated delta, 1 pole Standard spacing

1

1

5

3

5

3

4

5

5

Vertical, 1 pole Compact spacing

2

2

2

2

1

4

3

5

4

Rotated delta, 2 pole Compact spacing

5

5

3

4

5

1

5

5

5

Vertical, 2 pole braced Compact spacing

5

5

4

5

5

3

3

1

4

Vertical, 2 pole w/ arms Standard spacing

3

3

3

3

3

3

1

1

1

Delta, 2 pole Standard spacing

2

2

3

4

1

5

2

1

4

Rotated delta, 2 pole Standard spacing

(continued)

3

3

3

3

3

2

2

5

3

Delta, 2 pole Compact spacing

222 R. Stephen and J. Iglesias

Unit

1

Rotated delta, 1 pole Compact spacing

Cost comparison

% Baseline

100%

104%

1

Vertical, 1 pole Standard spacing

106%

5

Vertical, 2 pole braced Standard spacing

Structure configurations

Estimated cost comparison per mile

Line maintenance

Component

Structure configuration results

Table 8.9 (continued)

108%

1

Rotated delta, 1 pole Standard spacing

115%

1

Vertical, 1 pole Compact spacing

121%

2

Rotated delta, 2 pole Compact spacing

122%

5

Vertical, 2 pole braced Compact spacing

126%

5

Vertical, 2 pole w/ arms Standard spacing

126%

3

Delta, 2 pole Standard spacing

131%

2

Rotated delta, 2 pole Standard spacing

134%

3

Delta, 2 pole Compact spacing

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or demobilization costs. The estimated costs were only expected to be relatively accurate for the sake of comparison. As a conclusion, the estimated cost comparison results indicated costs varying by approximately 30% between the tower configurations considered. The vertical configurations provided the largest allowable span length; but achieving these longer spans required taller and heavier towers at each tower location. In most cases, the compact versions were more expensive solutions than the standard configurations; this was a result of the compact options requiring 4 subconductors per bundle in lieu of the 3 subconductors per bundle applied to the standard configurations to meet audible noise requirements. The choice of a preferred tower configuration was not based purely on economics. In addition to the consideration of costs, the selection of the preferred tower configuration considered the application of utility standards when possible. The selection also considered constructability and maintenance. Some of these components have related costs which were not reflected in the cost comparison. Additionally, these qualitative advantages can be significant to implementation and feasibility of any configuration. To best address the challenges anticipated, the recommended best approach was to select a primary tower configuration in combination with a secondary or complementary configuration that can be used individually or in combinations to address a wide variety of likely design situations. The selected primary tower configuration was the rotated delta, one-pole with standard spacing. The selected complementary configuration was the vertical, two-pole with standard spacing. These two tower configurations can be used individually or in combinations to address specific design challenges, including very poor soil conditions, narrower (pinch points) ROW, longer or shorter span requirements, tower height considerations, differing load zones, constructability issues, etc. all while meeting the criteria established.

8.10

DC Case Study: Prospect of Low Profile ± 400 kV Line (Spain)

The Spanish TSO, Red Eléctrica de España, has studied the conversion of an AC 400 kV line to DC operation. The objective was to assess the feasibility of expanding the planned international HVDC interconnection France-Spain, in order to reach a stronger node of the Spanish transmission grid, which could provide advantages in the system operation [8] (Fig. 8.48). For the existing AC 400 kV line to be converted to DC operation, it would be required to do partial modifications in the route, due to certain constrains, such as residential areas developed around the line. Therefore, portions of new line would be needed to avoid these critical areas. The new line portions would require compact designs to fulfil different requirements, like restricted Rights of Way, limitations on the visual impact or compatibility with other infrastructures.

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Fig. 8.48 Example of an alternative for AC to DC conversion of a 400 kV line

For comparative purposes, a line portion of 10 km is defined in a flat terrain. This can be representative of a route modification to avoid a residential area. A typical standard design for a HVDC line, ± 450 kV is summarized with the following parameters: • • • • • • • • •

Bipole Horizontal configuration. Pole spacing: 13 m Total tower height: 42 m Conductor: ACSR Cardinal @ 90 °C. 3 conductor/pole EDS 18% (after creep) Rated transmission capacity: 3150 MW (10 °C ambient, 0.6 m/s wind) Conductor minimum height above ground 12.5 m Conductor maximum sag 22.5 m Suspension string length: 5 m Average span 450 m (flat terrain).

If this standard line design was maintained in these route modifications, it may be probably difficult to get the necessary permissions due to the visual impact and the Right of Way needed. Therefore, a comparison with an alternative compact design is performed to identify the key aspects for compaction. In order to obtain general results that can be applicable to different cases, the focus is only on the main dimensional parameters of the line. For example, the maximum height of the towers can be limited to 22 m (almost half of the initial design), maintaining the rest of the characteristics unchanged. The following variations are obtained:

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Fig. 8.49 Comparison of tower height reduction from 42 to 22 m. Portion of plan-profile

• The average span reduces from 450 to 175 m • The number of towers increases from 2.2 per km to 5.7 per km (more than double). • The land occupation is reduced 1.88 times due to smaller blow-out • The loads on each tower (horizontal and vertical) are reduced 2.6 times. Therefore, the weight of the tower s and the foundations can be adjusted according to these loads. This can apply to the different tower types (self-supported lattice towers, guyed towers, T-pylons…), for which the comparison requires detailed designs for each one to obtain a final economical comparison. Also, factors like, for example, the ease of assembling, erecting, or maintaining much smaller and lighter supports, can be important (Fig. 8.49). Additionally, the use of lighter conductors could be included in this case to optimize the overall design. For example, using a composite cored conductor, which can operate at temperatures up to 150 ºC with a very small increase in sag, we could the use a twin bundle configuration instead of triple bundle (4 conductors in total, instead of 6) maintaining the same transmission capacity. This would reduce as much as 4 times the loads on the towers with respect to the standard design. Also, limitations to tower width can be introduced. For example, a simple rearrangement of the tower configuration, adjusting the pole-to-pole distance, can be proposed. In this regard, by using V-type insulator arrangements can reduce a pole-to-pole distance, decreasing the land occupation with respect to the standard design. Other insulation arrangements can also be proposed (horizontal Vee-type, Y or T assemblies…).

8.11

AC Case Study: Narrow ROW Tower (Japan)

A 275 kV two-circuit transmission line constructed in 1967 was needed to be renewed in order to increase transfer capacity. However, obtaining of new ROW was exceedingly difficult because surrounding areas of the existing line were urbanized in recent years. Therefore, it was required to minimize the horizontal phase spacing to reduce the ROW and increase the tower height to obtain more

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Fig. 8.50 Aerial view of line area in 1977, 10 years after construction (left) and 2007 (right)

ground clearance in response to requests from the residents living in the vicinity (Fig. 8.50). In this project, the following specifications were required: • • • • • •

Replace conductor bundle 2 × TACSR 410 mm2 with 4 × TACSR 810 mm2 (Capacity increase from 1221 to 3676 MW) Increase the bundle spacing from 0.4 to 0.5 m Increase the tower height Replace towers at the same place Minimize the horizontal spacing and the ROW.

Since the bundle spacing is increased, the horizontal spacing between outermost bundle centers must be reduced in order to place new conductors inside of the existing ROW. However, that is difficult because the phase configuration is determined to keep the clearance at the jumper. Furthermore, quad bundle requires more spacing to keep clearance between each bundle conductor and the tower. As a result, adoption of quad bundle instead twin bundle leads to larger size of jumper and hence horizontal spacing. Should the conventional tower be adapted, the horizontal spacing increases approximately from 11 to 12 m as shown in Fig. 8.51. Outline of Narrow ROW Tower The idea to minimize the ROW is shown in Fig. 8.52. The horizontal spacing of conventional tower is determined to keep the clearance at the jumper. In contrast, that of “Narrow ROW Tower” can be reduced so far as the phase-to-phase clearance in midspan permits by pulling the jumper toward outside. In Japan, ROW

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twin bundle (existing line)

quad bundle (replace with conventional towers)

Fig. 8.51 Required jumper clearance in the case of adopting 275 kV conventional tower

Fig. 8.52 ROW of existing line and narrow ROW tower

requires 3 m from the outermost conductor. Narrow ROW Tower can reduce the ROW width as well as the horizontal spacing of outermost bundle. The comparison of conventional tower and Narrow ROW Tower is shown below. The jumper of Narrow ROW Tower is pulled toward outside by long rod post insulator to keep the clearance at the jumper. In this way, the horizontal spacing in midspan can be reduced without the constraints of the jumper clearance (Figs. 8.53 and 8.54). Dimensions Table 8.10 shows the overview of the typical dimensions of existing line and new line replaced with Narrow ROW Tower. Minimum ground clearance of the existing line is determined by limits for electric field to conform with Japanese law (It should be less than 3 kV/m at 1 m above ground). In the case of new line, 9 m is added on the height determined by limits for electric field in order to take the height of 2-story buildings around the ROW into account (Fig. 8.55).

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Fig. 8.53 View of 275 kV conventional tower (left) and narrow ROW tower (right)

Fig. 8.54 Required jumper clearance for 275 kV narrow ROW tower

Phase to Phase Clearances in Midspan When Narrow ROW Tower is adopted, the phase configuration is determined to keep phase to phase clearances under the occurrence of asynchronous swing in midspan instead of jumper clearances. The swing angles calculated by equation below. The calculation takes the upwash angle of wind into account (Fig. 8.56).

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Table 8.10 Dimensions of existing line and new line replaced with narrow ROW tower Description

Existing line

New line (narrow ROW tower)

Span length

250–500 m

250–500 m

Conductor

2 × TACSR 410 mm2

4 × TACSR 810 mm2

Maximum working tension

49 kN

54 kN

Sag at zero wind (500 m span length, 15 °C of conductor temperature)

18.8 m

25.7 m

Minimum ground clearance

12 m

24 m

Tower height

50 m

75 m

Bundle spacing

0.4 m

0.5 m

Vertical phase spacing

6.2 m

8.5 m

Horizontal phase spacing

11 m

8.4 m

Determinant factor of horizontal phase spacing

Jumper clearance

Asynchronous swing of conductor in midspan

Fig. 8.55 Typical dimensions of existing tower and narrow ROW tower

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Fig. 8.56 Wind upwash angle and drag force

(

ρ/2 C V 2 d cos φ θ = arctan mg − ρ/2 C V 2 d sin φ

) (8.3)

where θ = swing angles ρ = air density (= 1.225 kg/m3 at 15 °C, 1013 hPa); C = drag factor (= 1.0); V = wind velocity; d = conductor diameter (= 0.0384 m); m = conductor mass (= 2.614 kg/m) g = gravitational acceleration (= 9.80665 m/s2 ) φ = wind upwash angle (= 10° considering the terrain). The 2σ of possible differences are taken into account: Conductor 1: θ – 2σ